Reducing the carbon emissions intensity of a fuel

ABSTRACT

Techniques for reducing a carbon emissions intensity of a fuel includes injecting a carbon dioxide fluid into a first wellbore; producing a hydrocarbon fluid from a second wellbore to a terranean surface; and producing a fuel from the produced hydrocarbon fluid, the fuel including a low-carbon fuel and assigned an emissions credit based on a source of the carbon dioxide fluid.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of, and claims priority under 35U.S.C. §120 to, U.S. patent application Ser. No. 13/600,484, entitled“REDUCING THE CARBON EMISSIONS INTENSITY OF A FUEL,” filed Aug. 31,2012, now U.S. Pat. No. 8,574,354 which in turn is a continuation of,and claims priority under 35 U.S.C. §120 to, International ApplicationNo. PCT/US2012/051424, filed Aug. 17, 2012, which in turn claimspriority to U.S. Provisional Patent Application Ser. No. 61/524,565,entitled “LOW-CARBON INTENSITY PRODUCTION OF HYDROCARBON FUELS,” filedAug. 17, 2011, and to U.S. Provisional Patent Application Ser. No.61/618,183, entitled “LOW-CARBON INTENSITY PRODUCTION OF HYDROCARBONFUELS,” filed Mar. 30, 2012. The entire contents of all of the previousapplications are incorporated by reference as if fully set forth herein.

TECHNICAL BACKGROUND

This disclosure relates to the production and/or supply of hydrocarbonproducts with low life-cycle emissions of greenhouse gases per unitfuel, referred to as low carbon intensity.

BACKGROUND

The burning of a hydrocarbon product (e.g., a hydrocarbon that has beenrefined into, for example, a transportation fuel, chemical, plastic, orotherwise), such as gasoline, produces emissions, such as, for example,carbon dioxide, carbon monoxide, sulfur dioxide, and other substances,many of which are often referred to as “greenhouse gases.” For example,it can be determined how much greenhouse gas (e.g., in grams of carbondioxide equivalent emissions) is emitted by the burning of a particularamount of gasoline (e.g., in units of grams carbon dioxide equivalentemissions per mega-joule of fuel energy). In many contexts it is usefulto determine the life-cycle greenhouse gas emissions from burning aparticular quantity of fuel considering all emissions sources associatedwith the fuel's production, supply, and use, not only emissionsresulting at the point of combustion. Lifecycle analysis (LCA) providesan analytic framework for such emissions determinations. The result fora particular fuel is often referred to as the fuel's lifecycle globalwarming intensity (GWI), carbon dioxide emission intensity, or simplycarbon intensity (CI), and may be used as a fuel-specific measure of airpollutant or greenhouse gas emissions on a lifecycle basis based on theamount of hydrocarbons or hydrocarbon products (e.g., transportationfuels, such as gasoline) burned, or combusted. In the context ofdetermining fuel CI, lifecycle analysis can be conceptualized as asystem of accounting for GHG flows to and from the atmosphere over thefuel's lifecycle, wherein flows to the atmosphere can representemissions debits and GHG flows from the atmosphere (e.g., via industrialprocess for direct air capture or via biological fixation duringphotosynthesis) and emissions reductions from supplying co-products canrepresent emissions credits.

SUMMARY

In one general implementation, a method for reducing a carbon emissionsintensity of a fuel includes injecting a carbon dioxide fluid into afirst wellbore; producing a hydrocarbon fluid from a second wellbore toa terranean surface; and producing a fuel from the produced hydrocarbonfluid, the fuel including a low-carbon fuel and assigned an emissionscredit based on a source of the carbon dioxide fluid.

In another general implementations, a method for reducing a carbonemissions intensity of a fuel includes capturing a carbon dioxide fluidfrom a source of carbon dioxide; and providing the captured carbondioxide fluid to a process for generating a low-carbon fuel that isassigned an emissions credit based on the source of the carbon dioxidefluid.

In another general implementation, a method for reducing a carbonemissions intensity of a fuel includes receiving a fuel refined from araw hydrocarbon fluid produced from a geologic formation into whichcaptured carbon dioxide fluid was injected; and providing the fuel as alow-carbon fuel that is assigned an emissions credit based on a sourceof the captured carbon dioxide fluid.

In another general implementation, a method of producing a hydrocarbonfuel with low life cycle carbon intensity includes receiving ahydrocarbon fluid that has been produced from a geologic formationthrough a wellbore to a terranean surface, the hydrocarbon fluidproduced, at least partially, from the geologic formation with a carbondioxide fluid injected into the geologic formation; and refining thereceived hydrocarbon fluid into a low-carbon fuel that is assigned anemissions credit based on a source of the carbon dioxide fluid injectedinto the geologic formation.

In a first aspect combinable with any of the general implementations,the source of the carbon dioxide fluid includes atmospheric carbondioxide supplied by at least one of an industrial process that capturescarbon dioxide from the atmosphere; or a biomass carbon dioxide sourceincluding carbon fixed from the atmosphere by photosynthesis.

In a second aspect combinable with any of the previous aspects, whereinthe industrial process includes directing ambient air through a packingmaterial; flowing a carbon dioxide absorbing fluid over the packingmaterial; capturing the atmospheric carbon dioxide in the carbon dioxideabsorbing fluid; separating the captured atmospheric carbon dioxide fromthe carbon dioxide absorbing fluid.

A third aspect combinable with any of the previous aspects furtherincludes receiving the captured atmospheric carbon dioxide; and usingthe received captured atmospheric carbon dioxide as the injected carbondioxide fluid into the first wellbore.

In a fourth aspect combinable with any of the previous aspects, thebiomass carbon dioxide source includes one of a biological processingthat receives biomass as an input and outputs the carbon dioxide fluidand a liquid fuel or chemical product; a process that includesgasification and receives biomass as an input and outputs the carbondioxide fluid and a hydrogen-containing product or intermediary product;a combustion process including post-combustion carbon capture thatreceives biomass as an input and outputs the carbon dioxide fluid and atleast one of electricity, heat, or power; or an oxyfuel combustionprocess that receives biomass as an input and outputs the carbon dioxidefluid and at least one of electricity, heat, or power.

In a fifth aspect combinable with any of the previous aspects, thesource of the carbon dioxide fluid is an industrial process thatsupplies one or more products and services, and the industrial processprovides a basis for at least one of a carbon intensity reductions or anemissions credit for at least one of the produced hydrocarbon fluid orthe fuel produced from the produced hydrocarbon fluid.

In a sixth aspect combinable with any of the previous aspects, the firstand second wellbores are the same wellbore.

A seventh aspect combinable with any of the previous aspects furtherincludes receiving at least a portion of the injected carbon dioxidefluid from the first wellbore at the terranean surface within thehydrocarbon fluid; separating the portion of the injected carbon dioxidefluid from the hydrocarbon fluid; and re-injecting the separated portionof the injected carbon dioxide fluid into the first wellbore.

An eighth aspect combinable with any of the previous aspects furtherincludes sequestering at least a portion of the injected carbon dioxidefluid in a subterranean zone.

In a ninth aspect combinable with any of the previous aspects, thelow-carbon fuel includes a low-carbon transportation fuel.

In a tenth aspect combinable with any of the previous aspects, theindustrial process includes capturing carbon dioxide from ambient air ina fluid.

In an eleventh aspect combinable with any of the previous aspects, thefluid is a carbon dioxide absorbing liquid, and capturing carbon dioxidefrom ambient air in a fluid includes directing ambient air through apacking material; flowing the carbon dioxide absorbing fluid over thepacking material; capturing the atmospheric carbon dioxide in the carbondioxide absorbing fluid; separating the captured atmospheric carbondioxide from the carbon dioxide absorbing fluid.

In a twelfth aspect combinable with any of the previous aspects, thelow-carbon fuel includes a low-carbon transportation fuel.

A thirteenth aspect combinable with any of the previous aspects furtherincluding completing a transaction to effect at least one of selling thelow-carbon fuel to a transportation fuel provider; selling the emissionscredit associated with the carbon intensity reduction to atransportation fuel provider or credit trading entity; or submitting thecredit to a regulatory agency responsible for regulating fuel carbonintensity.

In a fourteenth aspect combinable with any of the previous aspects, thelow-carbon fuel includes a low-carbon consumer transportation fuel.

In a fifteenth aspect combinable with any of the previous aspects, thesource of the carbon dioxide fluid is an industrial process thatsupplies other products and services, and atmospheric emissions from theindustrial process are reduced by the capture of carbon dioxide fluidfor hydrocarbon production, where the reduction provides a basis for thecarbon intensity reduction or emissions credits applied to the producedhydrocarbon fluid or the fuel produced from the produced hydrocarbonfluid.

In a sixteenth aspect combinable with any of the previous aspects, thesource of the carbon dioxide fluid is an industrial process thatsupplies other products and services, and the total atmosphericemissions from supplying those products and services and from supplyingthe produced hydrocarbon fluid or fuel produced from the producedhydrocarbon fluid is reduced in part by injecting the carbon dioxidefluid into a wellbore, and this reduction provides a basis for thecarbon intensity reduction or emissions credits applied to the producedhydrocarbon fluid or the fuel produced from the produced hydrocarbonfluid.

Other implementations may also include one or more computer-implementedmethods performed by a system of one or more computers. For example, ageneral implementation of a computer-implemented method for determiningat least one of an emissions intensity value or an emissions creditvalue for a hydrocarbon-based fuel includes: determining emissionsvalues for carbon dioxide supply, transportation, hydrocarbon fluidrecovery, hydrocarbon fluid transport, hydrocarbon fluid refining, andrefined hydrocarbon fluid transportation and storage; and determining atleast one of an emissions intensity value or an emissions credit valuefor the hydrocarbon fluid and or refined hydrocarbon fuel based in parton the determined emissions value for the source of carbon dioxide fluidsupplied for hydrocarbon production.

Various implementations of a system for producing and/or supplying alow-carbon transportation fuel according to the present disclosure mayinclude one or more of the following features and/or advantages. Forexample, the system may allow a hydrocarbon product (e.g., fuel)provider to meet a low-carbon fuel standard within a regulatory schemedirected at transportation fuels. The system may enable a fuel providerto achieve a particular fuel CI target or a particular reduction in fuelCI required to access certain fuel markets. Further, the system may helpreduce greenhouse gasses being emitted to the atmosphere, such as, forexample, carbon dioxide. The system may also allow a fuel provider thatis a carbon “debtor” (e.g., provide a transportation fuel that does notmeet a minimum standard) in a regulatory scheme to more efficiently buycarbon credits from a fuel provider that is a carbon “creditor” (e.g.,provide a transportation fuel that meets or exceeds a minimum standard)in the scheme. The system may also provide fuel providers that arecarbon debtors to lower a CI of their transportation fuels, potentiallybecoming carbon “creditors” or reducing the quantity of credits requiredto be acquired from carbon “creditors” to achieve compliance, withoutaltering the chemical composition of their transportation fuels. Furtheradvantages may include, for example, reducing anthropogenic GHGemissions from the production and use of hydrocarbon fuels and/orengineering carbon flows to and from the atmosphere and/or geologicformations associated with the production and use of hydrocarbons.

Further, a system for producing and/or supplying a low-carbontransportation fuel according to the present disclosure may reduce thecost of mitigating GHG emissions from anthropogenic activities reliantupon hydrocarbon fuels. A system for producing and/or supplying alow-carbon transportation fuel according to the present disclosure mayalso enable hydrocarbon fuel providers to generate emissions credits tocomply with regulations requiring fuel CI reductions at potentiallyreduced cost (e.g., without needing to purchase emissions credits fromother suppliers). A system for producing and/or supplying a low-carbontransportation fuel according to the present disclosure may also enablehydrocarbon fuel providers to generate emissions credits to balance anincreasing supply of high CI fuels under regulations requiringreductions in average fuel CI. A system for producing and/or supplying alow-carbon transportation fuel according to the present disclosure mayalso enable hydrocarbon fuel providers to generate emissions credits forbanking &/or sale to other regulated fuel suppliers. It may also enablesuppliers of hydrocarbon products to qualify fuels for sale in marketswith mandated CI threshold values or threshold CI reduction values.

These general and specific aspects may be implemented using a device,system or method, or any combinations of devices, systems, or methods,including computer-implemented methods. For example, a system of one ormore computers can be configured to perform particular actions by virtueof having software, firmware, hardware, or a combination of theminstalled on the system that in operation causes or cause the system toperform the actions. One or more computer programs can be configured toperform particular actions by virtue of including instructions that,when executed by data processing apparatus, cause the apparatus toperform the actions. The details of one or more implementations are setforth in the accompanying drawings and the description below. Otherfeatures, objects, and advantages will be apparent from the descriptionand drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 illustrates an example embodiment of a system for producing(e.g., from a wellbore) a low-carbon hydrocarbon according to thepresent disclosure;

FIGS. 2A-2C illustrate an example embodiment of a system for capturingatmospheric carbon dioxide for use in a system for producing and/orsupplying a low-carbon hydrocarbon fuel according to the presentdisclosure;

FIGS. 3A-3B illustrate example methods for accounting for carbon flowsand determining a regulatory value of a low CI hydrocarbon fuelaccording to the present disclosure;

FIG. 4 illustrates an example process for producing and/or supplying alow-carbon hydrocarbon fuel according to the present disclosure;

FIGS. 5A-5B illustrate schematic representations of example routes tocarbon dioxide capture systems;

FIG. 6 illustrates a schematic representation of example routes tobiomass with carbon dioxide capture systems; and

FIGS. 7A-7C illustrate example carbon dioxide separation systems.

DETAILED DESCRIPTION

The present disclosure describes techniques for producing hydrocarbons(e.g., a raw material recovered from a subterranean formation) and/orhydrocarbon products (e.g., fuel) with low life cycle greenhouse gasemissions that include injecting a carbon dioxide fluid into one or morewellbores, producing a hydrocarbon from one or more wellbores to aterranean surface, and supplying a low-carbon transportation fuel fromthe produced hydrocarbon fluid. Additional techniques include capturingcarbon dioxide; and providing the captured carbon dioxide to a processfor generating a transportation fuel including a low-carbon fuel.Additional techniques include injecting a carbon dioxide fluidcontaining carbon dioxide derived from an atmospheric source into asubterranean zone; and producing a hydrocarbon fluid from thesubterranean zone. Additional techniques include receiving a fuelrefined from a raw hydrocarbon fluid produced from a geologic formationinto which captured carbon dioxide was injected; and providing the fuelas a transportation fuel having a carbon emissions accounting creditbased at least in part on a fuel pathway that includes the injection ofthe captured carbon dioxide.

Such techniques may also be used to compare the environmental impact ofdifferent fuels, for example, such as different grades and/orcompositions of gasoline or other types of transportation fuels (e.g.,biofuels, natural gas, hydrogen, fuel electricity), or to compare theimpact of similar fuels produced from different feedstock or producedand supplied via different supply chains. Fuel supply chains can beorganized for the purposes of determining and/or reporting fuel CI intodiscrete “fuel pathways.” Fuel pathways may be specific to individualsupply chains or may represent broad categories of supply chains. Thespecific logistical means by which a fuel is supplied to a particularmarket can be described, characterized, and/or summarized to define thefuel's “physical pathway.”

Transportation fuels may be viewed based on their particular CI withincertain regulatory schemes, for example, schemes that define emissionsintensity values or threshold emission intensity reductions required toaccess certain fuel markets or to qualify fuels within certainregulatory fuel categories. Fuels may also be viewed based on theirrelative CI within a regulatory scheme (apart from the physical processof carbon dioxide emissions). For example, some fuels, such as ethanol,may have a relatively low CI within a regulatory scheme, for example, ascheme that facilitates the purchase and/or sale of carbon credits byentities regulated to meet certain standards. Other transportationfuels, such as diesel, may have a relatively high CI.

As noted above, although chemical content affects a particulartransportation fuel's carbon dioxide emissions intensity value, otherfactors may also affect this value. For example, particular life-cycleemissions from producing a raw hydrocarbon that is eventually refinedand/or otherwise processed into a particular fuel, including atransportation fuel, may affect the carbon dioxide emissions intensityvalue of the transportation fuel. Further, refining techniques toprocess the raw hydrocarbon into hydrocarbon products, for example, atransportation fuel, (if necessary) may affect the CI.

Also, mode(s) and distance of transporting the raw hydrocarbons,blendstock, and/or finished fuel within the supply chain or fuel pathway(e.g., from production site to user of the transportation fuel), such asby pipeline, truck, or other means, may also affect the CI. For example,in accounting for carbon flows and determining a regulatory value of ahydrocarbon fuel in a conventional scheme, CI values (e.g., in gCO₂e/MJ)may include values assigned for both a “well-to-tank” path (e.g., fuelproduction and supply to vehicles) and a “tank-to-wheel” path (e.g.,fuel combustion within vehicles). The well-to-tank path includes, forexample, CI values assigned for crude (e.g., raw hydrocarbon)production, crude transport, crude refining, and refined fuel transport.The tank-to-wheel path may include, for example, CI values assigned torepresent GHG generated in burning a mega joule (MJ) of refined fuel(e.g., gasoline). In one example accounting, approximate CI values (ingCO₂e/MJ) for the well-to-tank path include: 6.9 for crude production,1.1 for crude transport, 13.7 for crude refining, and 0.4 for refinedfuel transport. Thus, the total well-to-tank CI value is approximately22.2. The approximate CI value for the tank-to-wheel path may be 72.9.Accordingly, the total “well-to-wheel” regulatory CI value in thisexample for a hydrocarbon fuel in a conventional fuel pathway isapproximately 95 gCO₂e/MJ.

FIG. 1 illustrates an example embodiment of a system 100 for producinghydrocarbons with low life cycle greenhouse gas emissions. Asillustrated, system 100 includes a wellbore 110 formed from a terraneansurface 105 for producing a production fluid 130 from one or moresubterranean zones 135, 140, and/or 145. Typically, production fluid 130is a raw hydrocarbon, such as oil, natural gas, or other hydrocarbonthat may need further refinement and/or processing to form a hydrocarbonproduct, for example, a hydrocarbon transportation fuel (e.g., ahydrocarbon-based product used as a fuel for transporting livingcreatures and/or product on a terranean surface). For instance,production fluid 130 may be oil that is further refined to gasoline usedas a fuel for automobiles. Alternatively, production fluid 130 may be alow CI hydrocarbon, such as, for example, a raw hydrocarbon that neednot be further refined to have a low CI.

As illustrated, the system 100 also includes a tubing 120 extending fromat or near the terranean surface 105 into the wellbore 110 to form anannulus 115 between the tubing 120 and a wall of the wellbore 110. Thetubing 120 may be any appropriate tubular, such as threaded pipe orother tubular designed to be inserted into a wellbore, includingvertical, near-vertical, horizontal, articulated, radiussed,directional, or other type of wellbore. Indeed, although FIG. 1illustrates the wellbore 110 as a vertical bore, wellbore 110 may bedirectional, horizontal, articulated, or otherwise. For simplicity,drilling and/or production equipment known in the art to form wellboresand/or produce fluids from wellbores are omitted from FIG. 1. However,those of skill in the drilling and/or production arts will recognize thenecessary equipment, apparatus, and processes to form wellbore 110 andproduce production fluid 130 from the wellbore 110 to the terraneansurface 105 that may not be shown in FIG. 1.

As illustrated, an injection fluid 125 is provided into the wellbore 110(or the tubing 120) from the terranean surface 105. According to thepresent disclosure, the injection fluid 125 may be, for example, agreenhouse gas (in gaseous form, liquid form, or as a multiphase fluid).For example, in one embodiment, injection fluid 125 may be carbondioxide and, more particularly, atmospheric carbon dioxide captureddirectly via an industrial process (e.g., capturing from an industrialprocess output, such as a fossil fuel power plant, capturing viaatmospheric “scrubbing,” and/or otherwise), captured indirectly viabiological fixation of atmospheric carbon dioxide by photosynthesisfollowed by other industrial processes (e.g., oxidation of associatedbiomass carbon and capture of resulting carbon dioxide), a combinationthereof, or any other process in which carbon dioxide is captured fromthe atmosphere and/or from processes that would emit GHGs to theatmosphere and/or stored for later use. For instance, some specificexamples of carbon dioxide captured via an atmospheric process (orprocesses) are described with reference to FIGS. 2A-2C.

In some embodiments, “atmospheric carbon dioxide” may refer to carbondioxide in which the carbon content was resident in the atmospherewithin the last century. For example, “atmospheric carbon dioxide” mayrefer to carbon dioxide resident in the atmosphere due to fossil fuelcombustion plus carbon dioxide from biogenic sources may be resident inthe atmosphere for approximately a century. Alternatively, “atmosphericcarbon dioxide” may refer to carbon dioxide captured from the atmosphereusing industrial processes; carbon dioxide captured from the atmospherevia a biological process (e.g., photosynthesis) and followed by anindustrial process; and/or carbon dioxide produced from fossil fuelsthrough industrial processes that is captured specifically to avoid it'semission to the atmosphere.

The injection fluid 125 may be provided into the subterranean zones 135and/or 145 for a variety of purposes through one or more pathways 150and/or 155. The pathways 150 and/or 155 may be, for example,perforations made in the wellbore 110 (e.g., through casing(s),tubulars, and/or geologic formations) and/or fractures (e.g., throughcasing(s), tubulars, and/or geologic formations). Further, theproduction fluid 130 may be produced into the annulus 115 (or a tubular)through the pathways 150 and/or 155.

In some aspects of the system 100, the injection fluid 125 (e.g., carbondioxide) may be used in an enhanced oil recovery operation (or othertertiary recovery technique) to further produce the production fluids130 from the subterranean zones 135, 140, and/or 145. For instance, insome aspects, the enhanced oil recovery may be a gas reinjection inwhich carbon dioxide is injected into one or more of the subterraneanzones 135, 140, and/or 145 in order to, for example, increase a pressurewithin the zones and/or reduce a viscosity of the production fluid 130contained in the zones. In some embodiments, hydrocarbon displacement bycarbon dioxide injection may cause oil swelling and/or viscosityreduction (e.g., depending on, for instance, zone temperature, pressure,and hydrocarbon composition).

In some aspects of the system 100, a system of wellbores may be used inwhich the wellbore(s) from which hydrocarbons are produced may bedifferent from the wellbore(s) into which the injection fluid isinjected. Is these aspects, the fluid injection wellbores andhydrocarbon producing wellbores would be connected by subterranean zones(e.g., zones 135, 140, and/or 145) or systems of subterranean zonescontaining the hydrocarbons to be produced.

While carbon dioxide injection (e.g., carbon dioxide flooding) mayprovide for a use for captured carbon dioxide as the injection fluid 125(thereby decreasing greenhouse gases in the atmosphere), the carbondioxide injected into the zones 135, 140, and 145 may return with theproduction fluid 130. For instance, between 50-75% of the injectedcarbon dioxide may return with the production fluid 130. However, thereturned carbon dioxide may be separated from the production fluid 130and reinjected in some aspects of system 100. The remaining 25-50% ofthe injected carbon dioxide may remain in at least one of thesubterranean zones 135, 140, and/or 145.

In some aspects of system 100, all or most of the injection fluid 125may remain trapped in one or more of the subterranean zones 135, 140,and/or 145 (or other geologic formation). For example, in some aspects,the injection fluid 125 may be carbon dioxide, which is sequestered in asubterranean zone 135, 140, and/or 145 so as to remove greenhouse gassesfrom the atmosphere. In some aspects, providing carbon dioxide into theillustrated zones 135, 140, and/or 145 may include processes for:removing carbon from the atmosphere, either directly via industrialprocesses or indirectly via photosynthesis followed by other industrialprocesses, and depositing it in a geologic formation; capturing carbondioxide from an industrial process (e.g., such as flue gases from powerstations) that may otherwise be emitted to the atmosphere and injectingthe captured carbon dioxide into the one or more subterranean zones 135,140, and/or 145; and natural biogeochemical cycling of carbon betweenthe atmosphere and the one or more subterranean zones 135, 140, and/or145.

Although described as a “system,” system 100 may also be a sub-system ofa larger system for producing and/or supplying low life cyclehydrocarbons that further includes, for example, transportationsub-systems (e.g., pipelines, land-based transportation, water-basedtransportation, air-based transportation, and other techniques),refining and/or processing sub-systems (e.g., to refine a rawhydrocarbon, such as production fluid 130, into a transportation fuel),dispensing sub-systems (e.g., transportation fuel dispensing stationsfor commercial and private consumers), and other sub-systems.

In some embodiments of the system 100, using carbon dioxide (or othergreenhouse gas, for example) as the injection fluid 125 may reduce acarbon dioxide emission intensity of the production fluid 130 or othertransportation fuel derived (e.g., refined) from the production fluid130. For example, by using carbon dioxide as the injection fluid 125, alife cycle analysis of carbon content of a transportation fuel derivedfrom the production fluid 130 may be reduced due to, for instance,including a lifecycle accounting credit for the net removal of theinjected carbon dioxide from the atmosphere. In some instances,inclusion of such an accounting credit may enable the transportationfuel derived from the production fluid 130 to be classified as alow-carbon fuel. In particular, a hydrocarbon fuel produced from theproduction fluid 130 and having a lifecycle carbon dioxide emissionsaccounting credit reflecting injection of atmospheric carbon dioxidewithin the injection fluid 125 may define a new hydrocarbon fuel pathwayand/or be assigned a lifecycle CI value lower than that otherhydrocarbon fuels and/or lower than the value required under certainregulatory frameworks. In the case that the lifecycle CI value for sucha fuel pathway is lower than the regulatory value required, supply ofhydrocarbon fuels so produced may enable generation of tradableemissions credits, which can be used for the fuel supplier's owncompliance purposes or traded to other regulated parties.

In some cases, obtaining a credit for a transportation fuel requires anexus between the raw hydrocarbons used to produce the transportationfuel and the transportation fuel itself. For instance, referring to FIG.1, for example, any transportation fuel(s) refined from the productionfluid 130 may only qualify as low-carbon fuel(s) if the injection fluid125 was provided to the wellbore or system of wellbores from which theproduction fluid 130 is produced, as opposed to independent wellboresowned and/or operating by the same entity.

Thus, a transportation fuel provider that provides a low-carbon fuelaccording to the above-description of FIG. 1. The transportation fuelprovider may include, for example, any entity which owns title to a fuelwhen it is produced from, or enters into, a particular legaljurisdiction (e.g., a country, region, state, municipality, economicunion, other otherwise). The transportation fuel provider that providesa low-carbon fuel may thus be able to access markets designated for lowCI hydrocarbon products (e.g., fuels) and/or generate tradable emissionscredits, thus becoming a carbon “creditor” in a regulatory scheme thatincludes one or more standards or thresholds for a maximum or average CIfor a transportation fuel.

In conventional systems for producing and/or supplying a transportationfuel, a transportation fuel may be assigned a CI based on a standardvalue. The standard value may be determined according to, for example, alocation of a production site for raw hydrocarbons that are refined intothe transportation fuel (e.g., Texas, Canada, Saudi Arabia, etc.); aparticular geologic formation from which such raw hydrocarbons areproduced (e.g., shale, sandstone, etc.); and/or a delivery path betweenthe production site and final deliver (e.g., pipeline, groundtransportation, ocean transportation etc.).

FIGS. 2A-2C illustrate an example embodiment of a system for capturingatmospheric carbon dioxide for use in a system for producing and/orsupplying a low-carbon transportation fuel. For example, in someembodiments, the system(s) described with reference to FIGS. 2A-2C maycapture carbon dioxide, which is used as the injection fluid 125 insystem 100. For example, with reference to FIG. 2A in particular, acarbon dioxide capture facility 10 is illustrated including packing 12formed as a slab 15, the slab 15 having opposed dominant faces 14, theopposed dominant faces 14 being at least partially wind penetrable toallow wind to flow through the packing 12. At least one liquid source 16is oriented to direct carbon dioxide absorbent liquid into the packing12 to flow through the slab 15. The slab 15 is disposed in a wind flow18 that has a non-zero incident angle with one of the opposed dominantfaces 14. The packing 12 may be oriented to direct the flow of carbondioxide absorbent liquid through the slab 15 in a mean flow direction 20that is parallel to a plane 22 defined by the opposed dominant faces 14.It should be understood that opposed dominant faces 14 don't have to beexactly parallel. In one embodiment, the faces 14 may be converging,diverging, or curved for example. Packing 12 may be oriented to allowthe carbon dioxide liquid absorbent to flow through the packing 12 bygravity, as illustrated. In some embodiments, packing dimensions can beabout 200 m by about 20 m by about 3 m contained in a structuremeasuring about 200 m by 25 m by 7 m. In some embodiments, dimensionscan range from about 10 m by about 7 m by about 2 m to about 1000 m byabout 50 m about 15 m.

The non-zero incident angle refers to the fact that wind flow 18 strikesthe face 14 at an angle greater than zero. This may be contrasted withtraditional packing arrangements, where gas is flowed through a tower ofpacking starting from the very bottom. In some embodiments, the non-zeroincident angle is orthogonal with the one of the opposed dominant faces.It should be understood that the non-zero incident angle may be within10% of exactly orthogonal. The non-zero incident angle may also refer tothe mean angle of flow of the wind. The mean angle of flow of the windmay be averaged over a period of time.

In some embodiments, the packing 12 further includes structured packing.The packing 12 may be, for example, 1-2 meters thick between the opposeddominant faces 14. In other embodiments, the packing 12 may be thickeror thinner. The term structured packing may refer to a range ofspecially designed materials for use in absorption and distillationcolumns and chemical reactors. Structured packings typically consist ofthin corrugated material 24, such as metal plates or gauzes arranged ina way that they force fluids to take complicated paths through thecolumn, thereby creating a large face area for contact between differentphases. Structured packings may be made out of corrugated sheetsarranged in a crisscrossing relationship to create flow channels for thevapor phase. The intersections of the corrugated sheets create mixingpoints for the liquid and vapor phases. Wall wipers are utilized toprevent liquid and/or vapor bypassing along the column wall. Rotatingeach structured packing layer about the column axis provides crossmixing and spreading of the vapor and liquid streams in all directions.

The opposed dominant faces 14 may be oriented vertical. The orientationof faces 14 may be determined relative to, for example, the ground. Inother embodiments, faces 14 may be oriented at an angle to the ground,e.g., slanted. The opposed dominant faces 14 may be oriented horizontalin some embodiments. These embodiment tends to have a larger footprintthan the vertical slab embodiment. The packing 12 may be formed asplural slabs 15. Plural slabs may also be, for example, by plural slabsarranged end-to-end, as opposed to the stacked orientation illustratedin FIG. 2C. In some embodiments, the slab might be verticallysectionalized, effectively providing plural slabs end to end on top ofone another. This may be required in order to get sufficiently gooddistribution of liquid in such a narrow aspect ratio (e.g., 20 m high by1.5 m wide). Between the vertical sections there may be acollector/distributor system that collects fluid flowing from above andredistributes it evenly to the packing slab below. In some embodiments,such a collector/distributor system may be present in any slab asdisclosed herein.

The at least one liquid source 16 may further include at least one pump26. Pump 26 may have several distribution pipes 28, controlled by avalve (not shown), in order to selectively apply liquid into varioussections of packing 12. The at least one pump 26 may be configured tosupply the carbon dioxide absorbent liquid in a series of pulses.

At least one fan 30 may be oriented to influence wind flow through atleast a section of one of the opposed dominant faces 14 of the packing12. Fan 30 may be reversible. In some embodiments, fan 30 may preventthe wind flow that has already flowed through the packing 12 fromcirculating back into the packing 12. In some embodiments, at least onefan 30 may drive the wind flow into packing 12. Referring to FIG. 2A,the fan 30 may further include plural fans, each of the fans beingoriented to influence wind flow through at least a respective portion ofthe packing 12. In some embodiments, the respective portion isunderstood as being the portion of the packing 12 that air flow throughfan 30 would have the greatest influence over, for example the packing12 most adjacent or closest to fan 30. The at least one fan 30 may beprovided as part of a fan wall 32 adjacent at least one of the opposeddominant faces 14. It should be understood that fan walls (not shown)may be located adjacent each of faces 14. Adjacent, in this document, isunderstood to mean next to, and can include embodiments (such as the oneillustrated in the figures) where the fan wall 32 is spaced from, butadjacent to, face 14.

The fan wall 32 may be adjacent the one of the opposed dominant faces 14through which the wind flow 18 is exiting the packing 12. In fan wall32, the individual fans may be separated by impermeable material. Thefans 30 create a pressure drop across the wall 32, which drives flowthrough the packing 12. In some embodiments, fan wall 32 is designedsuch that, in the event that a fan fails, and ultimately blocks of itsrespective flow, flow through the packing 12 would be almost, if notcompletely, unaffected. This may be accomplished by closely spacingadjacent fans, and by spacing the fan wall 32 from the packing 12, forexample.

Facility 10 may further include wind guides 34 oriented to direct theflow of wind 18 into the packing 12. Facility 10 may further includewind guides 36 oriented to direct the flow of wind 18 out of the packing12. Wind guides 34 and 36 may be, for example, louvers. The wind guides34 and 36 may be independently controllable. In this embodiment, windflow 18 is directed from the right to the left. Thus, the upper windguides 34 are open, with the lower wind guides 34 closed. Similarly,upper wind guides 36 are closed, while lower wind guides 36 are open.Thus, wind flow 18 has a net flow from upper wind guides 24 to lowerwind guides 36, passing through packing 12 in the process.

The facility 10 may be part of an at least partially enclosed structure38. Because of the nature of the embodiments disclosed herein, thatbeing that they may involve the processing of great deals of wind, itmay be important to shield facility 10 from the elements, includinganimals and insects. Wind guides 36 and 34 may aid in this, along with asurrounding structure adapted to selectively let in and process windflow. In some embodiments, a protective covering (not shown) may beprovided over packing 12 to prevent animal intrusion but allow wind flowto pass through. A cleaning device 40 for cleaning the walls of the atleast partially enclosed structure 38 may be provided. Cleaning device40 may be, as illustrated for example, a wiper that rotates about anaxis to clean the exterior of fan wall 32, for example. Wind guides 34and 36 may be horizontally oriented, for example.

The facility 10 may further include at least one wind passage 42extended through the opposed dominant faces 14 to deliver wind flowselectively to one of the opposed dominant faces 14. Wind passage 42 mayhave fan 30 attached to influence air flow through wind passage 42. Windpassage 42 allows wind to travel through faces 14, where it is releasedinto basin 44, where the wind is free to pass into packing 12 throughface 14A, exiting the packing 12 through face 14B. This way, wind flowmay be induced to flow through the horizontal faces 14 of a horizontalslab of packing 12. Wind passages 42 may be, for example, air ducts thatare 10 m in height. In the embodiment illustrated, wind passages 42 arevertical ducts in which carbon dioxide rich inlet air is moving down.These ducts may cover .about.⅕ of the surface area (e.g., about 1.2 mdiameter tube arranged in a grid with 5 meter spacings).

A sink 46 may be provided for collecting carbon dioxide absorbent liquidthat has flowed through the packing 12. The sink is illustrated as basin44. Basin 44 may be, for example a concrete-lined basin that catches thehydroxide and contains supports to hold the packing. In some aspects,there may be a gap as illustrated between the packing 12 and the base 44that can be about 1 to 1.5 m for example. In some embodiments (notshown), sink 46 may be a pipe or a series of conduits for example, thattransport the liquid directly from packing 12. This type of system mayinvolve a funneling or drainage apparatus designed to focus the drainageof the liquid into a single, or a network of pipes. The contacted liquidmay then be recirculated through the packing, or it may be recycled andthen recirculated.

In some embodiments, facility 10 further includes a recycling system 48for regenerating spent carbon dioxide absorbent liquid. The recyclingsystem may be, for example, any system for recycling spent carbondioxide liquid absorbent. For example, the carbon dioxide absorbentliquid may include a hydroxide solution, for example a sodium hydroxidesolution. The source of liquid 16 preferably supplies recycled carbondioxide absorbent liquid.

Referring to FIGS. 2A-2B, a method of carbon dioxide capture isillustrated. Carbon dioxide absorbing liquid is applied into packing 12in a series of pulses. Referring to FIG. 2C, each pulse 50 may involve,for example, a short period during which the liquid is supplied intopacking 12 by source of liquid 16. Each pulse doesn't have to be a sharptransient application, but can be a period of time during which liquidis being supplied. A gas containing carbon dioxide, for example airillustrated by flow of wind 18, is flowed through the packing 12 to atleast partially absorb the carbon dioxide from the gas into the carbondioxide absorbing liquid. Applying may further include pumping. Flowingmay further include flowing the gas containing carbon dioxide throughthe packing at least when the carbon dioxide absorbing liquid is notbeing applied. The flow of gas may be controlled using fans 30, forexample. The flow of gas may be controlled using fans 30 and wind guides34 and 36. The flowing of the gas may be at least restricted when thecarbon dioxide absorbing liquid is being applied. This may be envisionedby the fans 30 of fan wall 32 ceasing to spin and draw the flow of windthrough packing 12 when the pulse of liquid is being supplied to packing12.

In some embodiments, the series of pulses has a duty cycle of 1-50%. Inother embodiments, the duty cycle may be 5% for example. The duty cyclerefers to the ratio of the time duration of a pulse of applied liquid tothe overall time duration of a cycle. For example, a 50% duty cycleimplies the fluid is only flowing half the time the facility isoperational. This means the pulse runs from 1 to 50% of the time thesystem is operational, and therefore a 1% duty cycle means that forevery second that fluid is flowing is off for 100 seconds. In morerealistic values, it is on for 30 seconds and off for 3000 seconds and a50% duty cycle means the pump would run for 30 seconds and be off forthe next 30 seconds. In some embodiments, the series of pulses has anoff-time of 10-1000 seconds. In other embodiments, the series of pulseshas an off-time of 100-10000 seconds.

The step of applying may further include applying the carbon dioxideabsorbing liquid into a first portion of the packing 12 in a firstseries of pulses, and applying the carbon dioxide absorbing liquid intoa second portion of the packing 12 in a second series of pulses. Thismay be envisioned by selectively applying liquid via distribution tubes28A and 28B to packing 12. Because tubes 28A and 28B only feed a portion(e.g., the left-most portion) of packing 12, only that portion will haveliquid applied to it. Liquid may then be selectively applied to theright hand portion of packing 12 by applying liquid via tubes 28C and28D. The first and second series of pulses may be synchronized,asynchronized, completely different, or synchronized out of phase withone another, for example, allowing fluids to be supplied intermittentlyfrom a continuously operating pump. In these embodiments, flowing thegas may further include at least restricting the flow of the gascontaining carbon dioxide through the first portion of the packing whenthe carbon dioxide absorbing liquid is not being applied, and at leastrestricting the flow of the gas containing carbon dioxide through thesecond portion of the packing when the carbon dioxide absorbing liquidis not being applied. Thus, while the first portion has liquid beingapplied to it, for example the left hand portion of face 14 when liquidis being applied via tubes 28A and 28B, the flow of gas may berestricted or stopped altogether through the left hand portion of face14. This may be accomplished by reducing, stopping, or even reversingfans 30A and 30B, for example. Similarly, while the second portion hasliquid being applied to it, for example the right hand portion of face14 when liquid is being applied via tubes 28C and 28D, the flow of gasmay be restricted or stopped altogether through the right hand portionof face 14. This may be accomplished by reducing, stopping, or evenreversing fans 30D and 30E, for example.

In some embodiments, the first series of pulses and the second series ofpulses are staggered. This may be advantageous, as when the left portionof face 14 has liquid being applied to it as described above, the righthand portion and center portions do not. Similarly, when the supply ofliquid to the left hand portion is ceased, the source of liquid 16 maythen apply liquid to the center or right hand portion, for example. Thisway, source of liquid 16 may cyclically feed liquid to the entire volumeof packing 12 in a more efficient manner, instead of continuouslyfeeding liquid to the entire volume of packing 12. In some aspects, anexample of this may be further envisioned, with a horizontal slab ofpacking 12. In such aspects, the flow of wind through any of the variouswind tubes 42 may be controlled, in order to achieve the same effect asthat achieved above with the vertical slab embodiment. Referring to FIG.2B, an embodiment is illustrated where only one wind tube 42A has windbeing driven down it. This may be achieved by the selective actuation offan 30A, for example. Thus, the packing 12 that is nearest the outlet ofwind tube 42A may have a flow of gas fed to it.

In some embodiments, the off-cycle of the series of pulses may be lessthan or equal to the time it takes for carbon dioxide absorbing liquidto stop draining from the packing after a pulse. It should be understoodthat this is not the time required for the entire pulse to be removedfrom the packing 12, since some liquid will always be left over asresidue inside the packing 12. In other embodiments, the off-cycle ofthe series of pulses may be less than or equal to the time it takes fora pulse of carbon dioxide absorbing liquid to lose 70-80% of the pulsescarbon dioxide absorption capacity.

The packing may be oriented to flow the carbon dioxide absorbing liquidthrough the packing 12 in a mean liquid flow direction 20. Flowing mayfurther include flowing the gas through the packing 12 obliquely orperpendicularly to the mean liquid flow direction 20. As disclosedabove, this is advantageous as the flow of gas may have a different flowdirection than, and one that is not counter current to, the mean liquidflow direction 20 of the liquid. Thus, a larger surface area of thepacking may be used to full advantage, greatly increasing the quantityof wind or gas that may contact liquid in packing 12 over a course oftime while still allowing the liquid to pass through and drain frompacking 12. In these embodiments, a slab is not entirely necessary, infact other shapes of packing 12 are envisioned, including but notlimited to a cube, a cylindrical, and other various shapes. Referring toFIG. 2A, in some embodiments flowing the gas further includes flowingthe gas through the packing 12 perpendicularly to the mean liquid flowdirection 20. It should be understood that exact perpendicularity is nota requirement. Flowing may further include flowing the gas through atleast one of the opposed dominant faces 14, for example through both offaces 14 as indicated.

These methods may involve recycling the carbon dioxide absorbing liquid.Also, the methods may involve influencing the flowing of the gas throughthe packing. Influencing may include, for example, preventing the gasthat has already flowed through the packing 12 from circulating backinto the packing 12. Influencing may further include driving the flowingof the gas in a drive direction that is at least partially oriented withan ambient wind flow direction. This may be carried out using fans 30,which may be reversible in order to carry out this function. Further,these methods may involve directing the flow of gas at least one of intoand out of the packing, using, for example louvers as already disclosed.

In some embodiments, fans 30 may be reversible in order to enable theflow to be driven in the direction of the ambient wind field, which ismore efficient than inducing a flow that is counter to the prevailingwind direction. In some aspects, the orientation of slabs 15 may be suchthat prevailing wind 18 is perpendicular to the slab 15, and is in thedirection at which the fan wall (not shown) works most efficiently. Thepacking design may use vertically oriented plates. This would be amodification of conventional structured packing designed to enable, forexample, orthogonal liquid and gas flow directions. Packing may be forintermittent fluid flow so as to maximize the hold up of liquidabsorbent inside the packing material. Referring to FIG. 2A, asdisclosed above, the fan wall 32 may be sectionalized, so that flowspeed can be reduced or stopped when fluid is flowing to minimize fluidloss. The sections may be operated asynchronously so that only onesection at a time is receiving the fluid flow enabling fluid pumps tooperate continuously. For example, if fluid flow was needed for 100seconds out of 1000 one may have 11 sections and would direct the fluidinto one of them at a time.

Compared to the horizontal slab geometry, the vertical slab may:minimize the footprint and the total structure size per unit of capacityto reduce the capital cost, reduce peak velocity, improve efficiency,and enables the packing to be operated at higher peak velocities furtherreducing capital costs.

Some embodiments may invoke the use of louvers to enable the flow to bedriven in the direction of the ambient wind without altering theoperation of the fans. For instance, the packing design may usingcoaxial flow or counter current flow, while still benefiting from thelarger surface area of the slab to increase the amount of wind flowthrough the slab. The flow geometry allows one to get even flow though alarge horizontal slab mounted just above a fluid reservoir whilemaintaining air speeds below about 5 msec. The air speed constraintdetermines the ratio of the structures height to its width.Specifically, height/width is approximately equal toairspeed-at-packing/air-speed-at-exit. Compared to the vertical slabgeometry, the horizontal slab has a larger footprint, and may havehigher costs, but it has the advantage that it may use more conventionalpacking and fluid distribution.

Referring to FIG. 2, another method of carbon dioxide capture isillustrated. Carbon dioxide absorbing liquid is flowed through packing12 in a mean liquid flow direction 20, a gas containing carbon dioxideis flowed through the packing 12 obliquely or perpendicularly to themean liquid flow direction 20 to at least partially absorb the carbondioxide from the gas into the carbon dioxide absorbing liquid. Flowingcarbon dioxide absorbing liquid through packing 12 may further includeapplying the carbon dioxide absorbing liquid into the packing 12 in aseries of pulses. The series of pulses has been disclosed in detailthroughout this document, and need not be built upon here. As disclosedabove, flowing the gas further may include flowing the gas through thepacking 12 perpendicularly to the mean liquid flow direction 20.

A method of contacting a liquid with a gas is also disclosed includingapplying the liquid into packing 12 in a series of pulses and flowingthe gas through the packing 12. While this method is also envisioned forsome of the embodiments herein, it may not be as efficient as the pulsedmethod, as it requires far greater pumping action. Thus, the pulsedmethod may be applied to any gas-liquid contactor, because it has beenproven herein to afford sufficient gas-liquid contact despite a lack ofcontinuous pumping. An exemplary application of this may be provided asa scrubbing unit at a refinery, for example. It should be understoodthat the gas-liquid contactor may have all of the same characteristicsas the carbon dioxide capture facility as disclosed herein.

Further disclosed is a method of contacting a liquid with a gasincluding flowing the liquid through packing in a mean liquid flowdirection, and flowing the gas through the packing obliquely orperpendicularly to the mean liquid flow direction. Similar to thegas-liquid contactor, this method may be applied to any gas-liquidcontact system. By having the gas flowed through the packing at anangle, the structure of such a contactor employing this method would begreatly simplified, since the gas inlet and outlet will be at differentlocations in the packing then the liquid source and sink. This methodmay have most or all of the same characteristics as the carbon dioxidecapture methods disclosed herein. For example, flowing the liquidthrough the packing may further include applying the liquid into thepacking in a series of pulses. Furthermore, flowing the gas may furtherinclude flowing the gas through the packing perpendicularly to the meanliquid flow direction.

Referring to FIG. 2A, a gas-liquid contactor (illustrated by facility10) is also disclosed. The contactor (illustrated as facility 10)includes packing 12 formed as a slab 15, the slab 15 having opposeddominant faces 14, the opposed dominant faces 14 being at leastpartially wind penetrable to allow wind to flow through the packing 12.At least one liquid source 16 is oriented to direct the liquid into thepacking 12 to flow through the slab 15. The slab is disposed in a windflow 18 that has a non-zero incident angle with one of the opposeddominant faces 14. It should be understood that this gas-liquidcontactor may have all of the same characteristics as the carbon dioxidecapture facility and contactor disclosed herein.

Referring to FIG. 2A, a gas-liquid contactor (illustrated by facility10) is also disclosed, including a slab 15 structure including packing12 and a liquid source 16 oriented to direct the liquid into the packing12 to flow in a mean liquid flow direction 20. The slab structure isdisposed in a wind flow 18 that flows obliquely or perpendicularly tothe mean liquid flow direction 20. It should be understood that thisgas-liquid contactor may have all of the same characteristics as thecarbon dioxide capture facility and contactor disclosed herein.

A method of contacting a liquid with a moving gas (illustrated as windflow 18) is also disclosed. The method includes flowing the liquidthrough packing 12, and driving the moving gas through the packing 12 ina drive direction (illustrated as 18B, which is the same as winddirection 18 in this embodiment) that is at least partially orientedwith an ambient flow direction 18 of the moving gas. In the embodimentshown, the flowing gas is wind, and the ambient flow direction is theambient wind direction 18. This method may further include reversing thedrive direction 18B when the ambient flow direction 18 reverses.Reversing the fan direction (or more generally, reversing the forcedflow of air through the packing) in such a way as to drive the air witha vector direction that is at least partially oriented with the ambientwind 18 reduces the required fan power. Further, this reduces the amountof low-carbon dioxide air that is recycled back into the inlet of thesystem, thus improving its efficiency. It is thus advantageous to alignthe packing such that one of opposed dominant face 14 is roughlyperpendicular to the prevailing wind, in order to maximize theefficiency of the fans.

Under some regulatory systems generically referred to as“cap-and-trade,” tradable emission rights are created, and it may bepossible for parties to create additional rights from “offsets” derivedfrom reductions in emissions that occur outside the set of emitters thatare directly regulated under the cap-and-trade system. The systemdisclosed here may be used to generate tradable emissions rights orreduce the number of tradable emissions rights that a regulated entitymust acquire to achieve compliance under cap-and-trade regulatorysystems.

The production of low CI hydrocarbon products is distinct from the typesof offsets often used within cap-and-trade regulatory systems, as theuse of the methods described herein allows the production of hydrocarbonproducts (e.g., transportation fuels and other products) having reducedCI values without the use of offsets from outside the productionprocess. This may be an advantage in regulatory systems that limit orexclude the use of economic offsets or that otherwise restrict emissionsaccounting to the production processes and supply chains used to provideparticular products or fuels.

Other systems for atmospheric carbon dioxide capture may also be used inthe disclosed system. These include, but are not limited to: directcapture of atmospheric carbon dioxide using solid sorbents that areregenerated using changes in temperature, moisture, and/or pressure toproduce a concentrated carbon dioxide gas. These systems may use, forexample, solid amines as or ion-exchange media as a solid sorbent mediafor carbon dioxide.

For example, capture of carbon dioxide can be applied to large pointsources, such as fossil fuel or biomass energy facilities, major carbondioxide-emitting industrial plants, natural gas production, petroleumproduction or refining facilities, synthetic fuel plants and fossilfuel-based hydrogen production plants. Turning in particular in FIGS.5A-5B, these figures illustrate schematic representations 500 and 550,respectively, of example routes to capture systems, including industrialsources of carbon dioxide (such as natural gas processing facilities andsteel and cement producers), oxyfuel combustion, pre-combustion (such ashydrogen and fertilizer production, and power plants using gaseous fuelsand/or solid fuels that are gasified prior to combustion), andpost-combustion facilities (such as heat and power plants). Forinstance, the schematic representation 500 shown in FIG. 5A illustratesfour different example routes to carbon dioxide capture systems.

The first example route 505 is an industrial separation route in which araw material and a fuel (e.g., a fossil fuel or biomass) is provided toan industrial process, which outputs a product containing carbondioxide. The carbon dioxide is separated from the product output andthen compressed through a compression process. Several industrialapplications involve process streams from which carbon dioxide can beseparated and captured. The industrial applications include for exampleiron, steel, cement and chemical manufacturers including ammonia,alcohol, synthetic liquid fuels and fermentation processes for food anddrink.

The second example route 510 is a post-combustion separation route inwhich the fuel and air is provided to a combustion process, whichoutputs heat, power, and a product containing carbon dioxide. The carbondioxide is separated from the product output and then compressed througha compression process. Capture of carbon dioxide from flue gasesproduced by combustion of fossil fuels (e.g., coal, natural gas, and/orpetroleum fuels) and biomass in air is referred to as post-combustioncapture. Instead of being discharged directly to the atmosphere, fluegas is passed through equipment which separates most of the carbondioxide from the balance of flue gases. The carbon dioxide may becompressed for transport and fed to a storage reservoir and theremaining flue gas is discharged to the atmosphere. A chemical sorbentprocess, including amine based sorbents, for example, is typically usedfor carbon dioxide separation in post combustion carbon dioxide capture(PCC).

The third example route 515 is a pre-combustion separation route inwhich the fuel and, for instance, air or oxygen and steam, is providedto a gasification process, which outputs hydrogen and carbon dioxide.The output is separated so that the carbon dioxide is then compressedthrough a compression process, and heat, power, and other products areextracted from the hydrogen. Pre-combustion capture may involve reactinga fuel with oxygen or air and/or steam to give mainly a “synthesis gas(syngas)” or “fuel gas” composed of carbon monoxide and hydrogen amongother compounds. The carbon monoxide may be reacted with steam in acatalytic reactor, called a shift reactor, to give a syngas rich incarbon dioxide and hydrogen. Carbon dioxide may be separated, usually bya physical or chemical absorption process, including glycol basedsolvents, for example, resulting in a hydrogen-rich fuel gas which canbe used in many applications, such as boilers, furnaces, gas turbines,engines, fuel cells, and chemical applications. Other common compoundsin syngas include, for example, carbon dioxide, methane, and higherhydrocarbons, which may be “cracked,” “reformed,” or otherwise processedto yield a desirable syngas composition, including, for example highconcentrations of hydrogen, carbon monoxide, and carbon dioxide.

The fourth example route 520 is an oxyfuel separation route in which thefuel and oxygen (e.g., separated from air) is provided to a combustionprocess, which outputs heat, power, and carbon dioxide that is thencompressed through a compression process. In oxy-fuel combustion, nearlypure oxygen is used for combustion instead of air, resulting in a fluegas that is mainly carbon dioxide and water. If fuel is burnt in pureoxygen, the flame temperature may be excessively high, but carbondioxide and/or water-rich flue gas can be recycled to the combustor tomoderate the temperature. Oxygen is usually produced by low temperature(cryogenic) air separation or other techniques that supply oxygen to thefuel, such as membranes and chemical looping cycles. The combustionsystems of reference for oxy-fuel combustion capture systems are thesame as those noted above for post-combustion capture systems, includingpower generation and/or heat production for industrial processes.

As another example, with reference to FIG. 6, a schematic representation600 is shown that illustrates routes to biomass with capture systems.For instance, schematic representation 600 illustrates a variety ofprocesses (e.g., biological processing such as fermentation,gasification such as oxygen blown or water blown, combustion with PCC,or oxyfuel combustion) to which biomass is provided. The resultantoutput(s) of the example processes in representation 600, as shown, iscarbon dioxide, liquid fuels and chemical products, hydrogen, andelectricity. Other outputs may include heat that can be used for avariety of purposes (e.g., electrical generation, industrial processes,comfort cooling processes, and others).

Separation techniques include separation with sorbents or solvents,membrane separation, and separation by cryogenic distillation.Separation with sorbents/solvents may be achieved by passing the passingthe carbon dioxide-containing gas in intimate contact with a liquidabsorbent or solid sorbent that is capable of capturing the carbondioxide. For example, FIG. 7A shows an example sorbent separationprocess 700 in which sorbent loaded with the captured carbon dioxide canbe transported to a different vessel, where it releases the carbondioxide (regeneration) after, for example, being heated, after apressure decrease, or after any other change in the conditions aroundthe sorbent. The sorbent resulting after the regeneration step can besent back to capture more carbon dioxide in a cyclic process. Thesorbent can be a solid and does not need to circulate between vesselsbecause the sorption and regeneration are achieved by cyclic changes (inpressure or temperature) in the vessel where the sorbent is contained. Amake-up flow of fresh sorbent can be introduced to compensate for thenatural decay of activity and/or sorbent losses. The sorbent can be asolid oxide which reacts in a vessel with fossil fuel or biomassproducing heat and mainly carbon dioxide. The spent sorbent can becirculated to a second vessel where it is re-oxidized in air for reusewith some loss and make up of fresh sorbent.

An example membrane separation process 725, as shown in FIG. 7B, mayutilize membranes (e.g., of specially manufactured materials) that allowthe selective permeation of a gas therethrough. The selectivity of themembrane to different gases is intimately related to the nature of thematerial, but the flow of gas through the membrane is usually driven bythe pressure difference across the membrane. Therefore, high-pressurestreams may be used for membrane separation. There are many differenttypes of membrane materials (e.g., polymeric, metallic, ceramic) thatmay find application in carbon dioxide capture systems to preferentiallyseparate hydrogen from a fuel gas stream, carbon dioxide from a range ofprocess streams or oxygen from air with the separated oxygensubsequently aiding the production of a highly concentrated carbondioxide stream.

FIG. 7C illustrates an example separation process 750 by cryogenicdistillation. A gas can be made liquid by a series of compression,cooling and expansion steps. Once in liquid form, the components of thegas can be separated in a distillation column. Oxygen can be separatedfrom air following the scheme of FIG. 7C and be used in a range ofcarbon dioxide capture systems (oxy-fuel combustion and pre-combustioncapture).

Turning now to FIGS. 3A-3B, these figures illustrate example methods foraccounting for carbon flows and determining a regulatory value of a lowCI hydrocarbon fuel. For example, some embodiments of producing and/orsupplying a low CI fuel operate within the context of various regulatorysystems, enabling the environmental benefits to be quantified andassociated with a raw hydrocarbon, hydrocarbon fuel, or a tradablecredit. Thus, these embodiments also can provide an economic incentive,which would not have existed prior to the implementation of suchregulatory systems, for affecting environmental objectives.

In one aspect, systems disclosed here for producing and/or supplying alow CI product (e.g., fuel) provide a computerized method of using adata processor having a memory to account for carbon flows and determinea regulatory value for a hydrocarbon fuel. The method includes (i)storing, in memory, a set of one or more values characterizing carbonflows associated with the production and use of hydrocarbon fuel(s),wherein one or more of the values represent injection of a fluidcontaining atmospheric carbon dioxide—captured either directly viaindustrial processes or indirectly via photosynthesis and industrialprocessing of resultant biomass and/or carbon dioxide captured fromindustrial processes that may otherwise be emitted to theatmosphere—into the geologic formation(s) from which raw hydrocarbonsare produced such that the injected atmospheric carbon dioxide issequestered in the geologic formation(s) and mitigates anthropogenic GHGemission, including but not limited to other emissions resulting fromproduction and use of the hydrocarbon fuel; and (ii) calculating, usingthe data processor, a regulatory value for the hydrocarbons from thestored carbon flow values.

In another aspect, systems disclosed here for producing and/or supplyinga low CI fuel provide a method of engineering a carbon cycle forhydrocarbon production and use. The method includes: (i) arranging theproduction of hydrocarbon fuel(s), wherein a fluid containingatmospheric carbon dioxide—captured either directly via industrialprocesses or indirectly via photosynthesis and industrial processing ofresultant biomass and/or carbon dioxide captured from industrialprocesses that may otherwise be emitted to the atmosphere—is injectedinto the geologic formation(s) from which raw hydrocarbons are producedsuch that the injected atmospheric carbon dioxide is sequestered in thegeologic formation(s) and mitigates anthropogenic GHG emission,including but not limited to other emissions resulting from productionand use of the hydrocarbon fuel; and (ii) assigning a regulatory valueto the bio fuel from a set of one or more carbon intensity valuescharacterizing the production and use of the hydrocarbon, including oneor more values characterizing the sequestration of atmospheric carbondioxide in the geologic formation from which raw hydrocarbons areproduced.

In yet another aspect, systems disclosed here for producing and/orsupplying a low CI fuel provide a method of manufacturing a hydrocarbonfuel. The method includes (i) injecting a fluid containing atmosphericcarbon dioxide into hydrocarbon containing geologic formation(s) suchthat a portion of atmospheric carbon dioxide is sequestered in thegeologic formation(s) and mitigates anthropogenic GHG emission, (ii)producing raw hydrocarbons from geologic formation(s) into which theatmospheric carbon dioxide containing fluid was injected and refiningraw hydrocarbons into finished hydrocarbon product fuels, and (iii)assigning a regulatory value to the hydrocarbon fuel based upon a one ormore carbon intensity values characterizing the production and use ofthe hydrocarbon, including one or more values characterizing thesequestration of atmospheric carbon dioxide in the geologicformation(s).

In still another aspect, systems for producing and/or supplying a low CIfuel disclosed here provide a computerized method of using a dataprocessor having a memory to account for carbon flows and determine aregulatory value for a hydrocarbon fuel. The method includes: (i)storing, in memory, a set of one or more values characterizing carbonflows associated with the production and use of hydrocarbon fuel(s),wherein one or more of the values represent injection of a fluidcontaining atmospheric carbon dioxide—captured either directly viaindustrial processes or indirectly via photosynthesis and industrialprocessing of resultant biomass and/or carbon dioxide captured fromindustrial processes that may otherwise be emitted to theatmosphere—into the geologic formation(s) from which raw hydrocarbonsare produced such that the injected atmospheric carbon dioxide issequestered in the geologic formation(s) and mitigates anthropogenic GHGemission, including but not limited to other emissions resulting fromproduction and use of the hydrocarbon fuel; (ii) calculating, using thedata processor, a regulatory value for the hydrocarbons from the storedcarbon flow values; and (iii) trading the hydrocarbon fuel having theregulatory value, a credit generated as a function of the regulatoryvalue, or both the hydrocarbon fuel and the credit.

In still another aspect, systems for producing and/or supplying a low CIfuel provide a method of engineering a carbon cycle for hydrocarbon fuelproduction and use. The method includes: (i) arranging the production ofhydrocarbon fuel(s), wherein a fluid containing atmospheric carbondioxide—captured either directly via industrial processes or indirectlyvia photosynthesis and industrial processing of resultant biomass and/orcarbon dioxide captured from industrial processes that may otherwise beemitted to the atmosphere—is injected into the geologic formation(s)from which raw hydrocarbons are produced such that the injectedatmospheric carbon dioxide is sequestered in the geologic formation(s)and mitigates anthropogenic GHG emission, including but not limited toother emissions resulting from production and use of the hydrocarbonfuel; (ii) assigning a regulatory value to the biofuel from a set of oneor more carbon intensity values characterizing the production and use ofthe hydrocarbon, including one or more values characterizing thesequestration of atmospheric carbon dioxide in the geologic formationfrom which raw hydrocarbons are produced; and (iii) trading thehydrocarbon fuel having the regulatory value, a credit generated as afunction of the regulatory value, or both the hydrocarbon fuel and thecredit.

In still another aspect, systems for producing and/or supplying a low CIfuel provide a method of manufacturing a hydrocarbon fuel. The methodincludes: (i) injecting a fluid containing atmospheric carbon dioxideinto hydrocarbon containing geologic formation(s) such that a portion ofatmospheric carbon dioxide is sequestered in the geologic formation(s)and mitigates anthropogenic GHG emission; (ii) producing rawhydrocarbons from geologic formation(s) into which the atmosphericcarbon dioxide containing fluid was injected and refining rawhydrocarbons into finished hydrocarbon fuels; (iii) assigning aregulatory value to the hydrocarbon fuel based upon a one or more carbonintensity values characterizing the production and use of thehydrocarbon, including one or more values characterizing thesequestration of atmospheric carbon dioxide in the geologicformation(s); and (iv) trading the bio fuel having the regulatory value,a credit generated as a function of the regulatory value, or both thehydrocarbon fuel and the credit.

Turning to FIG. 3A (and also with reference to Table 1, below), anexample scheme for accounting for carbon flows and determining aregulatory value of a low CI hydrocarbon fuel using CI values (e.g., ingCO₂e/MJ) is illustrated. More specifically, FIG. 3A illustrates anexample “well-to-wheel” accounting of CI values included with awell-to-tank path and tank-to-wheel path. Table 1, moreover, mayillustrate an example accounting of CI values for low CI hydrocarbonfuel production and/or supply using a natural gas fueled industrial aircapture of atmospheric carbon dioxide.

TABLE 1 Emissions summary for low Cl hydrocarbon production usingNatural Gas fueled industrial air capture Emissions LCA emissionsaccounting component (gCO2e/MJ) Well to tank Atmospheric CO2 capture−56.24 Computed below, Assumes full benefit allocated to transporationfuel product CO2 transportation 1.00 Placeholder value, but variabledependong on scale, distance, and mode of transport Crude Recovery 6.93Crude Transport 1.14 Crude Refining 13.72 Transport 0.36 Total well totank −33.09 Tank to wheel Total tank to wheel 72.91 Total well to wheel39.82 Example of computational algorithm for defining emissionsaccounting credits produced via low Cl hydrocarbon production applied inthe context of a Regulatory Low Carbon Fuel Standard Industrial aircapture Algorithm parameters CO2 sequestered per barrel hydrocarbonsproduced [tCO2e/bbl] 0.5 Hydrocarbon Lower Heating Value [GJ/bbl] 5.5Conversion factor: MJ per GJ 1000 Total CO2 sequestered [gCO2e/MJhydrocarbons] 90.91 Atmospheric CO2 sequestered [gCO2e/MJ hydrocarbons]60.61 Assumes: 0.5 tCO2e captured from NG for every 1 tCO2e capturedfrom the atmosphere Fuel combustion CO2 sequestered [gCO2e/MJhydrocarbons] 30.30 Same as above Fuel combustion emissions toatmosphere [gCO2e/MJ hydrocarbons] 3.37 Assumes 90% fuel combustion CO2capture rate Emissions from upstream fuel supply [gCO2e/MJ hydrocarbons]1 Placeholder value Emissions accounting credit for Atmospheric CO2sequestration 56.24 Computed as Atmospheric CO2 sequestered minusemissions from fuel combustion and upstream fuel supply

In some aspects, the CI value for the atmospheric capture of carbondioxide may be a negative value, e.g., a “credit,” relative to the CIvalues for other aspects of the illustrated well-to-tank path. Forinstance, the CI value for the atmospheric capture of carbon dioxide maybe determined according to the amount of atmospheric carbon dioxidesequestered per barrel of crude produced (in gCO₂e/bbl) minus a sum ofCI values for (1) emissions from natural gas combustion in atmosphericcarbon dioxide capture and (2) emissions associated with transport ofsuch natural gas. In one example accounting, a total amount ofatmospheric carbon dioxide sequestered per mega joules of crude producedis about 60.6. A CI value of emissions from natural gas combustion inatmospheric carbon dioxide capture is about 3.37. A CI value ofemissions associated with transport of such natural gas is about 1 (asan estimated value). Thus, the CI value for the atmospheric capture ofcarbon dioxide is about 56.2 (as a credit or negative value).

The CI value for carbon dioxide transportation may be determined on thebasis of, for example, scale, distance, and mode of transport. In thisexample, that value may be 1 gCO₂e/MJ as an estimate. The CI values forcrude recovery, crude transport, crude refining, and refined fueltransportation and storage may be substantially similar to the valuesprovided above in a conventional scheme: 6.9 for crude recovery, 1.1 forcrude transport, 13.7 for crude refining, and 0.4 for refined fueltransport (in gCO₂e/MJ).

As illustrated, therefore, the total CI value for the well-to-tank pathis determined by subtracting the CI value of atmospheric capture ofcarbon dioxide from the sum of the CI values for carbon dioxidetransportation, crude recovery, crude transport, crude refining, andtransport and/or storage of refined fuel. The well-to-tank value,according to the above example accounting, therefore, is about 33.1gCO₂e/MJ in credit (e.g., a negative value). As noted above, the CIvalue for the tank-to-wheel CI value is about 72.9 gCO₂e/MJ, therebygiving a well-to-wheel CI value in this example of about 39.8.Accordingly, the total estimated well-to-wheel CI value for low CIhydrocarbon fuel production and/or supply using a natural gas fueledindustrial air capture of atmospheric carbon dioxide is 39.8 compared toa total estimated well-to-wheel CI value for conventional schemes forproducing and/or supplying hydrocarbon fuel of 95.1.

As another example of a scheme for accounting for carbon flows anddetermining a regulatory value of a low CI hydrocarbon fuel using CIvalues using FIG. 3A (and now with reference to Table 2, below), anexample accounting of CI values for low CI hydrocarbon fuel productionand/or supply using a biomass fueled industrial air capture ofatmospheric carbon dioxide is illustrated.

TABLE 2 Emissions summary for low Cl hydrocarbon production usingbiomass fueled industrial air capture Emissions LCA emissions accountingcomponent (gCO2e/MJ) Well to tank Atmospheric CO2 capture −89.91Computed below CO2 transportation 0.10 Placeholder value, but variabledependong on scale, distance, and mode of transport Crude Recovery 6.93Crude Transport 1.14 Crude Refining 13.72 Transport 0.36 Total well totank −67.66 Tank to wheel Total tank to wheel 72.91 Total well to wheel5.25 Example of computational algorithm for defining emissionsaccounting credits produced via low Cl hydrocarbon production applied inthe context of a Regulatory Low Carbon Fuel Standard - Biomass fueledindustrial air capture Algorithm parameters CO2 sequestered per barrelhydrocarbons produced [tCO2e/bbl] 0.5 Hydrocarbon Lower Heating Value[GJ/bbl] 5.5 Conversion factor: MJ per GJ 1000 Total CO2 sequestered[gCO2e/MJ hydrocarbons] 90.91 Atmospheric CO2 sequestered from Aircapture [gCO2e/MJ hydrocarbons] 60.61 Assumes: 0.5 tCO2e captured fromNG for every 1 tCO2e captured from the atmosphere, which includes energyrequired for CO2 compression Fuel combustion CO2 from biogenic sourcessequestered [gCO2e/MJ hydrocarbons] 30.30 Same as above Fuel combustionemissions from biogenic sources to atmosphere [gCO2e/MJ 3.37 Assumes 90%fuel combustion hydrocarbons] CO2 capture rate—does not affect total CO2emissions due to biogenic source Emissions from upstream fuel supply[gCO2e/MJ hydrocarbons] 1 Place holder Emissions accounting credit forAtmospheric CO2 sequestration 89.91 Computed as Atmospheric CO2 fromindustrial air capture plus fuel combustion CO2 from biogenic sourcessequestered minus emissions from fuel combustion and upstream fuelsupply

As noted above, the CI value for the atmospheric capture of carbondioxide is a negative value, e.g., a “credit,” relative to the CI valuesfor other aspects of the illustrated well-to-tank path. For instance,the CI value for the atmospheric capture of carbon dioxide may bedetermined according to the amount of atmospheric carbon dioxidesequestered per barrel of crude produced (in gCO₂e/bbl) plus a fuelcombustion carbon dioxide from biogenic sources emissions minus theemissions associated with fuel combustion and an upstream fuel supply.In one example accounting, a total amount of atmospheric carbon dioxidesequestered per mega joules of crude produced is about 60.6. A CI valueof a fuel combustion carbon dioxide sequestered from biogenic sourcesemissions is about 30.3. A CI value of emissions associated with fuelcombustion and an upstream fuel supply is about 1 (as an estimatedvalue). Because biogenic carbon dioxide was recently captured from theatmosphere (e.g., via photosynthesis, the CI value for the atmosphericcapture of carbon dioxide is about 89.9 gCO₂e/MJ (as a credit ornegative value).

The CI value for carbon dioxide transportation may be determined on thebasis of, for example, scale, distance, and mode of transport. In thisexample, that value may be about 0.1 gCO₂e/MJ as an estimate. The CIvalues for crude recovery, crude transport, crude refining, and refinedfuel transportation and storage may be substantially similar to thevalues provided above in a conventional scheme: 6.9 for crude recovery,1.1 for crude transport, 13.7 for crude refining, and 0.4 for refinedfuel transport (in gCO₂e/MJ).

As illustrated, therefore, the total CI value for the well-to-tank pathis determined by subtracting the CI value of atmospheric capture ofcarbon dioxide from the sum of the CI values for carbon dioxidetransportation, crude recovery, crude transport, crude refining, andtransport and/or storage of refined fuel. The well-to-tank value,according to the above example accounting, therefore, is about 67.7gCO₂e/MJ in credit (e.g., a negative value). As noted above, the CIvalue for the tank-to-wheel CI value is about 72.9 gCO₂e/MJ, therebygiving a well-to-wheel CI value of about 5.2. Accordingly, the totalestimated well-to-wheel CI value for low CI hydrocarbon fuel productionand/or supply using a biomass fueled industrial air capture ofatmospheric carbon dioxide is 5.2 compared to a total estimatedwell-to-wheel CI value for conventional schemes for producing and/orsupplying hydrocarbon fuel of 95.1.

Turning to FIG. 3B (and with reference to Table 3, below), anotherexample scheme for accounting for carbon flows and determining aregulatory value of a low CI hydrocarbon fuel using CI values (e.g., ingCO₂e/MJ) is illustrated. More specifically, FIG. 3B illustrates anexample “well-to-wheel” accounting of CI values included with awell-to-tank path and tank-to-wheel path. Table 3, moreover, mayillustrate an example accounting of CI values for low CI hydrocarbonfuel production and/or supply using a biomass carbon capture and storage(“CCS”) with electricity as a co-product.

TABLE 3 Emissions summary for low Cl hydrocarbon production usingbiomass CCS with electricity co-product Emissions LCA emissionsaccounting component (gCO2e/MJ) Well to tank Atmospheric CO2 capture−89.91 Computed below Atmospheric CO2 capture co-product credit −30.30Computed below CO2 transportation 1.00 Placeholder value, but variabledepending on scale, distance, and mode of transport Crude Recovery 6.93Crude Transport 1.14 Crude Refining 13.72 Transport 0.36 Total well totank −97.06 Tank to wheel Total tank to wheel 72.91 Total well to wheel−24.15 Example of computational algorithm for defining emissionsaccounting credits produced via low Cl hydrocarbon production applied inthe context of a Regulatory Low Carbon Fuel Standard - Biomass- CCS withelectricity co-product Algorithm parameters Value Notes Atmospheric CO2sequestered CO2 sequestered per barrel hydrocarbons produced [tCO2e/bbl]0.5 Hydrocarbon Lower Heating Value [GJ/bbl] 5.5 Conversion factor: MJper GJ 1000 Total CO2 sequestered - all from biogenic sources [gCO2e/MJhydrocarbons] 90.91 Biomass combustion emissions to atmosphere [gCO2e/MJhydrocarbons] 10.10 Assumes 90% fuel combustion CO2 capture rate - doesnot affect total CO2 emissions due to biogenic source Emissions fromupstream fuel supply [gCO2e/MJ hydrocarbons] 1 Assumed Total credit foratmospheric CO2 sequestered 89.91 Co-product credit Biomass CO2eproduced [g/MJ hydrocarbons] 101.01 Biomass carbon content [massfraction] 0.50 Biomass burned [g/MJ hydrocarbons] 55.10 Computed asproduct of CO2e produced, mass ratio of C:CO2 (12/44), and inverse of Ccontent of biomass Biomass heating value (HHV) [kJ/g] 15.00 Biomass toelectricity conversion efficiency with CCS [HHV basis] 0.20 Includesparasitic loads for CO2 compression Conversion factor: kJ per kWh3500.00 Electricity generated [kWh/bbl] 0.05 Computed as the inverse ofthe conversion factor multiplied by the product of the preceeding threefactors Carbon intensity of electricity generated [gCO2e/kWh] 0 Assumesall emissions are biogenic and upstream emissions of fuel supply areaccounted for above Carbon intensity of conventional electricitydisplaced [gCO2e/kWh] 650 Approximate value for US average (in 2005)from an ICFS presentation on fuel electricity Total co-product credit[gCO2e/MJ hydrocarbons] 30.30

For instance, electricity produced in the supply of carbon dioxide forcarbon capture and storage may be considered a co-product of thehydrocarbon fuels. In this case, the emissions consequence ofsubstituting resulting electricity for conventionally producedelectricity may be attributed to the hydrocarbon using, for example,system expansion and/or displacement LCA methodologies. Use ofallocation LCA methodologies is also possible, though not discussed inthis example. This is computed as the product of electricity producedper unit hydrocarbon fuels and the difference in emissions intensity(e.g., CI value) of the produced electricity and a conventional sourceof electricity (such as, for example, a coal-fired power plant). If theelectricity is produced using biomass fuel, then the carbon dioxidesequestered constitutes atmospheric carbon dioxide, which was fixed inthe biomass via photosynthesis. Residual emissions from electricityproduction (e.g., carbon dioxide not captured) may be assigned a netemissions value of zero in certain contexts. An appropriate baselinesource of electricity might be determined, as explained in the exampleof FIG. 3B below.

A wide variety of technologies are available for using biomass to supplycarbon dioxide for hydrocarbon production with an electricityco-product. Further, it is possible to produce a wide variety ofco-products other than electricity in the process of using biomass tosupply carbon dioxide for hydrocarbon production including but notlimited to: liquid fuels using thermochemical (e.g., Fischer-Tropschesynthesis) or biochemical (e.g., fermentation) processes; chemicals;solid fuels (e.g., charcoal); soil amendments (e.g., bio-char); or theco-products noted below in the context of supplying carbon dioxide fromfossil carbon sources. Many types of biomass could be used for supplyingcarbon dioxide for hydrocarbon production including but not limited to:agricultural residues; forestry residues; mill wastes; urban wastes;municipal solid wastes; clippings, trimmings, or other “green wastes”;or landfill deposits, with associated landfill gas production. Multipletypes of biomass, technologies, and co-products may be usedsimultaneously or in other combinations for supplying carbon dioxide forhydrocarbon production.

If the electricity is produced using coal fuel, then the carbon dioxidesequestered does not constitute atmospheric carbon dioxide, and so nonegative CI value can be granted for atmospheric carbon dioxidesequestration. However, an emissions accounting credit (e.g., a negativeCI value) may be granted for displacing conventional electricitygeneration with the reduced CI electricity co-product of hydrocarbonproduction. The emissions intensity of the produced electricity can becomputed as the combustion emissions to the atmosphere plus theemissions associated with fuel supply divided by the associatedelectricity produced. If the coal fired power plant with CCS supplyingthe coal is displacing electricity that would be provided by aconventional coal fired power plant without CCS, then the difference inthese CIs may be the appropriate basis for computing net emissionseffects from using the electricity co-product. This can yield asignificant co-product credit.

A wide variety of technologies are available for using fossil carbonsources, such as coal in the present discussion, to supply carbondioxide for hydrocarbon production with an electricity co-product.Further, it is possible to produce a wide variety of co-products otherthan electricity in the process of using fossil carbon sources to supplycarbon dioxide for hydrocarbon production including but not limited to:liquid fuels (e.g., via Fischer-Tropsche synthesis); fertilizers;cement; mineral products (e.g., lime and soda ash) metals (e.g., ironand steel, aluminum, zinc, or lead); other chemicals (e.g., ammonia,petrochemicals, urea, fertilizer, and titanium dioxide); or steam for avariety of processes, including for thermally enhanced oil recovery,steam injection bitumen production, and/or bitumen upgrading. Many typesof fossil carbon sources could be used for supplying carbon dioxide forhydrocarbon production including but not limited to: coal, natural gas,and petroleum. Multiple types of fossil carbon sources, technologies,and co-products may be used simultaneously or in other combinations forsupplying carbon dioxide for hydrocarbon production.

Turning to FIG. 3B again, the CI value for the atmospheric capture ofcarbon dioxide may be substantially the same CI value (e.g., 89.9gCO₂e/MJ) as that determined above with reference to FIG. 3A and theexample accounting of CI values for low CI hydrocarbon fuel productionand/or supply using a biomass fueled industrial air capture ofatmospheric carbon dioxide. As described above, there is also a CI valuecredit for electricity generated as a co-product from atmospheric carbondioxide capture. This CI value may be determined by first determining anamount of electricity generated (in kWh/MJ) as a co-product, which canbe determined according to the biomass burned (in g/MJ crude) and thebiomass heating value (in kJ/g). More specifically, the electricitygenerated as a co-product is equal to the biomass burned times thebiomass heating value times a biomass to electricity conversionefficiency with CSS divided by a kJ to kWh conversion factor. Assumingthat the biomass burned is equal to the total carbon dioxide sequesteredfrom biogenic sources plus the biomass combustion emissions to theatmosphere (taking into account the mass ratio of carbon to carbondioxide and the carbon content of biomass), then the biomass burned isabout 101 g/MJ. Also assuming a HHV of biomass as 15 kJ/g, then theelectricity generated is about 0.05 kWh/MJ crude.

In order to determine the CI value (credit) of the electricityco-product, the CI value of conventional electricity generation must beapproximated—in this example, it is about 660 gCO₂e/kWh. Thus, the CIvalue credit is equal to the CI value of conventional electricitygeneration times the amount of co-produced electricity (e.g., 0.05kWh/MJ crude), or about 30.3 gCO₂e/MJ crude.

The total CI credit value is thus the sum of the CI value due to theatmospheric capture of carbon dioxide (e.g., 89.9 gCO₂e/MJ) and the CIvalue of conventional electricity generation times the amount ofco-produced electricity (e.g., 0.05 kWh/MJ crude), or about 30.3gCO₂e/MJ crude. This sum is about 120.2 gCO₂e/MJ.

The CI value for carbon dioxide transportation may be determinedrelative to, for example, scale, distance, and mode of transport. Inthis example, that value may be 1 gCO₂e/MJ as an estimate. The CI valuesfor crude recovery, crude transport, crude refining, and refined fueltransportation and storage may be substantially similar to the valuesprovided above in a conventional scheme: 6.9 for crude recovery, 1.1 forcrude transport, 13.7 for crude refining, and 0.4 for refined fueltransport (in gCO₂e/MJ).

As illustrated, therefore, the total CI value for the well-to-tank pathis determined by subtracting the sum of the CI values of atmosphericcapture of carbon dioxide and the atmospheric carbon dioxide captureco-products from the sum of the CI values for carbon dioxidetransportation, crude recovery, crude transport, crude refining, andtransport and/or storage of refined fuel (values shown above). Thewell-to-tank value, according to the above example accounting,therefore, is about 97.1 gCO₂e/MJ in credit (e.g., a negative value). Asnoted above, the CI value for the tank-to-wheel CI value is about 72.9gCO₂e/MJ. Accordingly, the total estimated well-to-wheel CI value forlow CI hydrocarbon fuel production and/or supply using a biomass CSSwith electricity as a co-product is 24.2 gCO₂e/MJ in credit (negativevalue) compared to a total estimated well-to-wheel CI value forconventional schemes for producing and/or supplying hydrocarbon fuel of95.1 gCO₂e/MJ (positive value).

In a related example to that described above with reference to FIG. 3B(and now with reference to Table 4, below), this figure and table mayalso illustrate an example accounting of CI values for low CIhydrocarbon fuel production and/or supply using a coal electricity withCCS (e.g., with electricity as a co-product). In this related example,however, there is no capture of atmospheric carbon dioxide. Thus thereis no credit for capturing atmospheric carbon dioxide and there is nosequestration of captured atmospheric carbon dioxide. Instead, there isa co-product credit for the electricity generated by a coal plant fromwhich emitted carbon dioxide is sequestered. For instance, the CI valueof the total carbon dioxide sequestered (e.g., all from fossil sources)is about 90.9 gCO₂e/MJ hydrocarbons produced. The coal combustionemissions to the atmosphere is assumed to be ˜11% more than thesequestered carbon dioxide, for the case that there is an assumed 90%fuel combustion carbon dioxide capture rate in this example.

TABLE 4 Emissions summary for low Cl hydrocarbon production using coalelectricity with CCS Emissions LCA emissions accounting component(gCO2e/MJ) Well to tank Atmospheric CO2 capture 0.00 Computed belowAtmospheric CO2 capture co-product credit −75.77 Computed below CO2transportation 1.00 Placeholder value, but variable dependong on scale,distance, and mode of transport Crude Recovery 6.93 Crude Transport 1.14Crude Refining 13.72 Transport 0.36 Total well to tank −52.52 Tank towheel Total tank to wheel 72.81 Total well to wheel 20.29 Example ofcomputational algorithm for defining emissions accounting creditsproduced via low Cl hydrocarbon production applied in the context of aRegulatory Low Carbon Fuel Standard - Biomass- CCS with electricityco-product Algorithm parameters Value Notes Atmospheric CO2 sequesteredCO2 sequestered per barrel hydrocarbons produced [tCO2e/bbl] 0.5Hydrocarbon Lower Heating value [GJ/bbl] 5.5 Conversion factor: MJ perGJ 1000 Total CO2 sequestered - all from fossil sources [gCO2e/MJhydrocarbons] 90.91 Coal combustion emissions to atmosphere [gCO2e/MJhydrocarbons] 10.10 Assumes 90% fuel combustion CO2 capture rate - doesnot affect total CO2 emissions due to biogenic source Emissions fromupstream fuel supply [gCO2e/MJ hydrocarbons] 10 Assumed Total credit foratmospheric CO2 sequestered 0.00 None of the sequestered carbon is fromthe atmosphere Co-product credit Coal CO2e produced [g/MJ hydrocarbons]101.01 Coal carbon content [mass fraction] 0.75 Coal burned [g/MJhydrocarbons] 36.73 Computed as product of CO2e produced, mass ratio ofC:CO2 (12/44) and inverse of C content of biomass Coal heating value(HHV) [kJ/g] 29.50 Coal to electricity conversion efficiency with CCS[HHV basis] 0.27 Conversion factor: kJ per kWh 3600.00 Electricitygenerated [kWh/bbl] 0.00 Computed as the inverse of the conversionfactor multiplied by the product of the preceeding three factors Carbonintensity of electricity generated [gCO2e/kWh] 252 Assumes all emissionsare biogenic and upstream emissions of fuel supply are accounted forabove Carbon intensity of conventional electricity displaced [gCO2e/kWh]1220 Approximate value for coal steam plant from an ICFS presentation onfuel electricity Total co-product credit [gCO2e/MJ hydrocarbons] 75.77

The CI value of the electricity generated, therefore, is the sum of theCI value of the coal combustion emissions to the atmosphere (in thisexample, about 10.1 gCO₂e/MJ) plus an assumed CI value for upstream fuelsupply emissions (in this example, assumed to be about 10 gCO₂e/MJ)divided by the electricity generated per barrel of produced hydrocarbons(in this example, about 0.5 kWh/W. Thus, the CI of the electricitygenerated is about 252 gCO₂e/MJ.

In order to determine the CI value (credit) of the electricityco-product, the CI value of conventional electricity generation must beapproximated—in this example, it is about 1200 gCO₂e/kWh (assuming anapproximate value for a coal steam plant). The total CI credit value isthus the difference between the CI of the electricity generated (e.g.,252 gCO₂e/MJ) and the CI value of conventional electricity generation(e.g., 1200 gCO₂e/kWh) times the amount of co-produced electricity(e.g., 0.05 kWh/MJ crude), or about 75.8 gCO₂e/MJ.

The CI value for carbon dioxide transportation may be determinedrelative to, for example, scale, distance, and mode of transport. Inthis example, that value may be 1 gCO₂e/MJ as an estimate. The CI valuesfor crude recovery, crude transport, crude refining, and refined fueltransportation and storage may be substantially similar to the valuesprovided above in a conventional scheme: 6.9 for crude recovery, 1.1 forcrude transport, 13.7 for crude refining, and 0.4 for refined fueltransport (in gCO₂e/MJ).

As illustrated, therefore, the total CI value for the well-to-tank pathis determined by subtracting the CI value (credit) of the electricityco-product from the sum of the CI values for carbon dioxidetransportation, crude recovery, crude transport, crude refining, andtransport and/or storage of refined fuel (values shown above). Thewell-to-tank value, according to this related example accounting,therefore, is about 52.6 gCO₂e/MJ in credit (e.g., a negative value). Asnoted above, the CI value for the tank-to-wheel CI value is about 72.9gCO₂e/MJ. Accordingly, the total estimated well-to-wheel CI value forlow CI hydrocarbon fuel production and/or supply using a coalelectricity with CCS is 20.3 gCO₂e/MJ, which is about 75 gCO₂e/MJ lessthan the total estimated well-to-wheel CI value for conventional schemesfor producing and/or supplying hydrocarbon fuel of 95.1 gCO₂e/MJ(positive value).

As another example illustrated by FIG. 3B (and now with reference toTable 5, below), this figure and table may illustrate an exampleaccounting of CI value for low CI hydrocarbon fuel production and/orsupply using ethanol fermentation offgas. In this example, theatmospheric carbon dioxide capture co-product may be assumed to be zero,as ethanol plant operations may not be affected other than a plant powerload increased for carbon dioxide compression and sequestration, whichare accounted for in the CI value of the atmospheric capture of carbondioxide.

TABLE 5 Emissions summary for low Cl hydrocarbon production usingethanol fermentation offgas Emissions LCA emissions accounting component(gCO2e/MJ) Well to tank Atmospheric CO2 capture −83.41 Computed belowAtmospheric CO2 capture co-product credit 0.00 Assumed to be zero CO2transportation 1.00 Placeholder value, but variable dependong on scale,distance, and mode of transport Crude Recovery 6.93 Crude Transport 1.14Crude Refining 13.72 Transport 0.36 Total well to tank −60.26 Tank towheel Total tank to wheel 72.91 Total well to wheel 12.65 Example ofcomputational algorithm for defining emissions accounting creditsproduced via low Cl hydrocarbon production applied in the context of aRegulatory Low Carbon Fuel Standard - Ethanol fermentation offgasAlgorithm parameters Value Notes Atmospheric CO2 sequestered CO2sequestered per barrel hydrocarbons produced [tCO2e/bbl] 0.5 HydrocarbonLower Heating Value [GJ/bbl] 5.5 Conversion factor: MJ per GJ 1000 TotalCO2 sequestered - all from ethanol offgases [gCO2e/MJ hydrocarbons]90.91 Carbon intensity of electricity [gCO2e/kWh] 660.00 Electricityrequired for ethanol offgas compression [kWh/tCO2e] 125.00 Fossil CO2emissions from CO2 compression [gCO2e/MJ hydrocarbons] 7.50 Assumes zeroenergy required for CO2 capture Marginal Emissions from upstream fuelsupply [gCO2e/MJ hydrocarbons] 0 Assumes upstream emissions areallocated to the ethanol production/no change in upstream emissions fromimplementing CO2 capture Total credit for atmospheric CO2 sequestered83.41 Co-product credit Total co-product credit [gCO2e/MJ hydrocarbons]0.00 Assumed to be zero, as ethanol plant emissions are not affectedother than power load for CO2 compression and CO2 sequestration, bothcaptured above.

In this example, the CI value for the atmospheric capture of carbondioxide may be determined by, for instance, subtracting an amount ofcarbon dioxide emissions (in gCO₂e/MJ) for carbon dioxide compressionfrom a CI value representing the total carbon dioxide sequestered. TheCI value representing the total carbon dioxide sequestered isapproximately equal to the amount of carbon dioxide sequestered perbarrel of hydrocarbon produced (in this example, 0.5 tCO₂e/bbl) dividedby the hydrocarbon's lower heating value (in this example, about 5.5gJ/bbl) and then multiplied by a conversion factor to convert the unitsinto gCO₂e/MJ hydrocarbons produced. In this example, therefore, thetotal atmospheric carbon dioxide sequestered is about 90.9 gCO₂e/MJ.Thus, the CI value for the atmospheric capture of carbon dioxide is 90.9minus 7.5 gCO₂e/MJ, which represents (in this example) the CI value forcarbon dioxide compression, or about 83.4 gCO₂e/MJ in credit (e.g., anegative value).

The CI value for carbon dioxide transportation may be determinedrelative to, for example, scale, distance, and mode of transport. Inthis example, that value may be 1 gCO₂e/MJ as an estimate. The CI valuesfor crude recovery, crude transport, crude refining, and refined fueltransportation and storage may be substantially similar to the valuesprovided above in a conventional scheme: 6.9 for crude recovery, 1.1 forcrude transport, 13.7 for crude refining, and 0.4 for refined fueltransport (in gCO₂e/MJ).

As illustrated, therefore, the total CI value for the well-to-tank pathis determined by subtracting the CI value of atmospheric capture ofcarbon dioxide from the sum of the CI values for carbon dioxidetransportation, crude recovery, crude transport, crude refining, andtransport and/or storage of refined fuel (values shown above). Thewell-to-tank value, according to the above example accounting,therefore, is about 60.3 gCO₂e/MJ in credit (e.g., a negative value). Asnoted above, the CI value for the tank-to-wheel CI value is about 72.9gCO₂e/MJ. Accordingly, the total estimated well-to-wheel CI value forlow CI hydrocarbon fuel production and/or supply using ethanolfermentation offgas is 12.7 gCO₂e/MJ (positive value) compared to atotal estimated well-to-wheel CI value for conventional schemes forproducing and/or supplying hydrocarbon fuel of 95.1 gCO₂e/MJ (positivevalue).

FIG. 4 illustrates an example process 400 for producing and/or supplyinga low-carbon transportation fuel. In some aspects, the process 400 maybe implemented, at least in part, by all or portions of the system 100and the system(s) described with reference to FIGS. 2A-2C.Alternatively, or additionally, the process 400 may be implemented byand/or with a system for producing and/or supplying a low-carbontransportation fuel in accordance with the present disclosure.

At step 402, atmospheric carbon dioxide is captured through biogenicfixation (e.g., photosynthesis). In step 404, atmospheric carbon dioxideis captured through an industrial process. At step 406, an industrialprocess occurs that takes biogenic material (e.g., biomass) as input andproduces carbon dioxide as output. In step 414, an industrial processmay have reduced carbon dioxide emissions. As illustrated, each of steps402, 404, and 414 describe a distinct step in capturing atmosphericcarbon dioxide. For example, in step 402, atmospheric carbon dioxide iscaptured through biological fixation via photosynthesis. In step 404,atmospheric carbon dioxide is captured through an industrial process.For example, step 404 may include the capture of atmospheric carbondioxide through one or more processes described with reference to FIGS.2A-2C. Further, in step 414, fossil-generated carbon dioxide may becaptured from an industrial application (e.g., coal powered electricitygeneration using a biomass CCS).

For example, in some embodiments, step 402 may include capturingatmospheric carbon dioxide through fermentation off-gases from ethanolproduction. Step 402 may also include biomass combustion with CCS,either via oxyfuel or post-combustion capture with amine solvents. Step402 may also include biomass co-combustion with fossil fuels (e.g.,coal) with CCS such that a fraction of resultant carbon dioxide is frombiomass.

More specifically, in some embodiments, biomass may have importantsimilarities with fossil fuels (particularly coal), including conversiontechnologies and the range of energy products that can be generated,including dispatchable, base-load electricity as well as liquid andgaseous fuels. As a result, the technological routes for CCSapplications with fossil fuel systems could be applied to biomass energysystems, and biological processes, such as bio-ethanol fermentation,provide additional CCS opportunities for biomass.

In some embodiments, carbon dioxide can be separated from othercombustion products, for example by using amine based solvents orburning the fuels with concentrated carbon dioxide so that resultingcombustion products are primarily carbon dioxide and water, which can beseparated by condensing the water. These technological routes to CCScould be integrated with new biomass boiler technologies or retrofittedto existing plants. Alternatively, fossil fueled facilities (e.g.,coal-fired power plants) could be retrofitted to co-fire biomass andincorporate CCS such that a portion of the carbon dioxide captured wouldbe from biogenic sources and a portion would be from fossil sources.With sufficiently stringent emissions controls, such a plant could beretrofitted to burn only biomass.

In some embodiments, combustion could be preceded by gasification and/orsyngas conditioning with carbon dioxide separation. Technological routesusing these basic processes could be integrated with modern and advancedbiomass gasification technologies, including for example, indirectlyheated, steam-blown systems or oxygen blown systems. Alternatively,technological routes using these basic technologies could be integratedwith facilities that co-fire or co-gasify coal and biomass.

Further, carbon dioxide is produced as a byproduct of fermentation inequal molar proportions to ethanol. This nearly pure carbon dioxidestream is normally vented to the atmosphere, but could be captured andcompressed for geologic storage. For example, nearly 35 metric tons ofcarbon dioxide is available for capture (at potentially very low costs)from fermentation of approximately 46 gigaliters ethanol producedannually. Further, bio-ethanol production—particularly inligno-cellulosic systems—generally also includes combustion, orgasification and combustion, of waste biomass, providing further carboncapture opportunities.

Carbon dioxide may be produced as a byproduct of other biological orthermochemical processes including but not limited to anaerobicdigestion, landfill gas production, fermentation into alcohols otherthan ethanol, hydrothermal treatments/upgrading, liquefaction,pyrolysis, refining, gas conditioning, and many others.

Steps 402 and 404 may be performed simultaneously, sequentially, invarying order, or independently. Further, only one of steps 402 and 404may be performed to capture atmospheric carbon dioxide. In otherinstances, the steps 402 and 404 may be performed together orindependently. In addition, other steps and/or processes for capturingatmospheric carbon dioxide (not shown here) may be implemented in placeof or together with one or more of steps 402 and 404.

In step 408, the captured carbon dioxide is provided into a subterraneanzone through a wellbore (or other technique). For example, as shown inFIG. 1, an injection fluid 125 such as carbon dioxide may be used in anenhanced oil recovery operation (or other secondary or tertiaryoperation) or in a sequestration operation. In any event, at least someof the captured atmospheric carbon dioxide is used in a productionand/or sequestration operation.

In step 410, hydrocarbons (e.g., oil, gas, etc.) are produced from thewellbore. For example, as described above with respect to FIG. 1, aproduction fluid 130 is produced from the same wellbore into which theinjection fluid 125 (e.g., captured atmospheric carbon dioxide) isprovided. In other instances, an injection fluid may be provided intoone or more injection wells in a secondary and/or tertiary productionprocess to help produce hydrocarbons from a production well.

In step 412, a low-carbon hydrocarbon product (e.g., transportationfuel) is produced from the raw hydrocarbon produced from the wellbore.As described above, in some embodiments, using carbon dioxide as aninjection fluid may reduce a CI of a transportation fuel refined from aproduction fluid. For example, the life cycle CI of such atransportation fuel may be reduced due to, for instance, accounting forthe removal of the injected carbon dioxide from the atmosphere. In someinstances, the transportation fuel is a low-carbon fuel, e.g., ahydrocarbon fuel with a carbon emissions accounting credit that reflectsinjection of atmospheric carbon dioxide during hydrocarbon production.

None, one, some, or all implementations of the subject matter and thefunctional operations described in this disclosure can be implemented indigital electronic circuitry, in tangibly-embodied computer software orfirmware, in computer hardware, including the structures disclosed inthis specification and their structural equivalents, or in combinationsof one or more of them. None, one, some, or all implementations of thesubject matter described in this specification can be implemented in oneor more computer programs, e.g., one or more modules of computer programinstructions encoded on a tangible non-transitory program carrier forexecution by, or to control the operation of, data processing apparatus.Alternatively or in addition, the program instructions can be encoded onan artificially-generated propagated signal, e.g., a machine-generatedelectrical, optical, or electromagnetic signal that is generated toencode information for transmission to suitable receiver apparatus forexecution by a data processing apparatus. The computer storage mediumcan be a machine-readable storage device, a machine-readable storagesubstrate, a random or serial access memory device, or a combination ofone or more of them.

The term “data processing apparatus” refers to data processing hardwareand encompasses all kinds of apparatus, devices, and machines forprocessing data, including by way of example a programmable processor, acomputer, or multiple processors or computers. The apparatus can also beor further include special purpose logic circuitry, e.g., a centralprocessing unit (CPU), a FPGA (field programmable gate array), or anASIC (application-specific integrated circuit). In some implementations,the data processing apparatus and/or special purpose logic circuitry maybe hardware-based and/or software-based. The apparatus can optionallyinclude code that creates an execution environment for computerprograms, e.g., code that constitutes processor firmware, a protocolstack, a database management system, an operating system, or acombination of one or more of them. The present disclosure contemplatesthe use of data processing apparatuses with or without conventionaloperating systems, for example Linux, UNIX, Windows, Mac OS, Android,iOS or any other suitable conventional operating system.

A computer program, which may also be referred to or described as aprogram, software, a software application, a module, a software module,a script, or code, can be written in any form of programming language,including compiled or interpreted languages, or declarative orprocedural languages, and it can be deployed in any form, including as astand-alone program or as a module, component, subroutine, or other unitsuitable for use in a computing environment. A computer program may, butneed not, correspond to a file in a file system. A program can be storedin a portion of a file that holds other programs or data, e.g., one ormore scripts stored in a markup language document, in a single filededicated to the program in question, or in multiple coordinated files,e.g., files that store one or more modules, sub-programs, or portions ofcode. A computer program can be deployed to be executed on one computeror on multiple computers that are located at one site or distributedacross multiple sites and interconnected by a communication network.While portions of the programs illustrated in the various figures areshown as individual modules that implement the various features andfunctionality through various objects, methods, or other processes, theprograms may instead include a number of sub-modules, third partyservices, components, libraries, and such, as appropriate. Conversely,the features and functionality of various components can be combinedinto single components as appropriate.

All or portions of the processes and logic flows described in thisspecification can be performed by one or more programmable computersexecuting one or more computer programs to perform functions byoperating on input data and generating output. The processes and logicflows can also be performed by, and apparatus can also be implementedas, special purpose logic circuitry, e.g., a central processing unit(CPU), a FPGA (field programmable gate array), or an ASIC(application-specific integrated circuit).

Computers suitable for the execution of a computer program include, byway of example, can be based on general or special purposemicroprocessors or both, or any other kind of central processing unit.Generally, a central processing unit will receive instructions and datafrom a read-only memory or a random access memory or both. The essentialelements of a computer are a central processing unit for performing orexecuting instructions and one or more memory devices for storinginstructions and data. Generally, a computer will also include, or beoperatively coupled to receive data from or transfer data to, or both,one or more mass storage devices for storing data, e.g., magnetic,magneto-optical disks, or optical disks. However, a computer need nothave such devices. Moreover, a computer can be embedded in anotherdevice, e.g., a mobile telephone, a personal digital assistant (PDA), amobile audio or video player, a game console, a Global PositioningSystem (GPS) receiver, or a portable storage device, e.g., a universalserial bus (USB) flash drive, to name just a few.

Computer-readable media (transitory or non-transitory, as appropriate)suitable for storing computer program instructions and data include allforms of non-volatile memory, media and memory devices, including by wayof example semiconductor memory devices, e.g., EPROM, EEPROM, and flashmemory devices; magnetic disks, e.g., internal hard disks or removabledisks; magneto-optical disks; and CD-ROM and DVD-ROM disks. The memorymay store various objects or data, including caches, classes,frameworks, applications, backup data, jobs, web pages, web pagetemplates, database tables, repositories storing business and/or dynamicinformation, and any other appropriate information including anyparameters, variables, algorithms, instructions, rules, constraints, orreferences thereto. Additionally, the memory may include any otherappropriate data, such as logs, policies, security or access data,reporting files, as well as others. The processor and the memory can besupplemented by, or incorporated in, special purpose logic circuitry.

To provide for interaction with a user, implementations of the subjectmatter described in this specification can be implemented on a computerhaving a display device, e.g., a CRT (cathode ray tube), LCD (liquidcrystal display), or plasma monitor, for displaying information to theuser and a keyboard and a pointing device, e.g., a mouse or a trackball,by which the user can provide input to the computer. Other kinds ofdevices can be used to provide for interaction with a user as well; forexample, feedback provided to the user can be any form of sensoryfeedback, e.g., visual feedback, auditory feedback, or tactile feedback;and input from the user can be received in any form, including acoustic,speech, or tactile input. In addition, a computer can interact with auser by sending documents to and receiving documents from a device thatis used by the user; for example, by sending web pages to a web browseron a user's client device in response to requests received from the webbrowser.

The term “graphical user interface,” or GUI, may be used in the singularor the plural to describe one or more graphical user interfaces and eachof the displays of a particular graphical user interface. Therefore, aGUI may represent any graphical user interface, including but notlimited to, a web browser, a touch screen, or a command line interface(CLI) that processes information and efficiently presents theinformation results to the user. In general, a GUI may include aplurality of user interface (UI) elements, some or all associated with aweb browser, such as interactive fields, pull-down lists, and buttonsoperable by the business suite user. These and other UI elements may berelated to or represent the functions of the web browser.

Implementations of the subject matter described in this specificationcan be implemented in a computing system that includes a back-endcomponent, e.g., as a data server, or that includes a middlewarecomponent, e.g., an application server, or that includes a front-endcomponent, e.g., a client computer having a graphical user interface ora Web browser through which a user can interact with an implementationof the subject matter described in this specification, or anycombination of one or more such back-end, middleware, or front-endcomponents. The components of the system can be interconnected by anyform or medium of digital data communication, e.g., a communicationnetwork. Examples of communication networks include a local area network(LAN), a wide area network (WAN), e.g., the Internet, and a wirelesslocal area network (WLAN).

The computing system can include clients and servers. A client andserver are generally remote from each other and typically interactthrough a communication network. The relationship of client and serverarises by virtue of computer programs running on the respectivecomputers and having a client-server relationship to each other.

While this specification contains many specific implementation details,these should not be construed as limitations on the scope of anyinvention or on the scope of what may be claimed, but rather asdescriptions of features that may be specific to particularimplementations of particular inventions. Certain features that aredescribed in this specification in the context of separateimplementations can also be implemented in combination in a singleimplementation. Conversely, various features that are described in thecontext of a single implementation can also be implemented in multipleimplementations separately or in any suitable sub-combination. Moreover,although features may be described above as acting in certaincombinations and even initially claimed as such, one or more featuresfrom a claimed combination can in some cases be excised from thecombination, and the claimed combination may be directed to asub-combination or variation of a sub-combination.

Similarly, while operations are depicted in the drawings in a particularorder, this should not be understood as requiring that such operationsbe performed in the particular order shown or in sequential order, orthat all illustrated operations be performed, to achieve desirableresults. In certain circumstances, multitasking and parallel processingmay be advantageous. Moreover, the separation of various system modulesand components in the implementations described above should not beunderstood as requiring such separation in all implementations, and itshould be understood that the described program components and systemscan generally be integrated together in a single software product orpackaged into multiple software products.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made. For example, thesteps of process 400 may be performed in a different order than thatillustrated herein. Further, process 400 may include more or fewer stepsthan those illustrated herein.

In addition, there may be other techniques to capture atmospheric carbonthat may be utilized in production and/or supply of hydrocarbon fuelswith low life-cycle emissions of greenhouse gases per unit fuel,referred to as low carbon intensity. For example, carbon dioxide may beall or part of a gaseous stream provided to a contactor through aninlet. The gaseous stream may be, for example, air, flue gas (e.g., froman industrial facility), exhaust gas (e.g., from a vehicle), or anygaseous stream including a target species such as carbon dioxide. Thecontactor facilitates absorption of carbon dioxide gas by an aqueoussolution (e.g., transfer of the target species carbon dioxide from thegaseous stream to the aqueous solution) in the contactor. In some cases,the aqueous solution is an aqueous buffer solution including one or morebuffer species. The aqueous solution may be basic, with a pH greaterthan 7, greater than 8, greater than 10, or greater than 12, while thebuffer species in the aqueous solution can be ionic or neutral, organicor inorganic, or any combination thereof. An initial concentration ofbuffer species may be selected to achieve a desired equilibrium amongspecies in aqueous solution, including the target species carbondioxide.

Further, the aqueous solution may include a catalyst selected toincrease the rate of absorption of carbon dioxide by the aqueoussolution. In an example, carbonic anhydrase is used as a catalyst inaqueous solution, at a concentration of 1-10 g/L, to increase the rateof absorption of carbon dioxide by (or transfer of carbon dioxide to)the aqueous solution.

In an example, a contactor as described above may be configured toachieve cross-current flow of the gaseous stream through the aqueoussolution, thereby facilitating absorption of carbon dioxide by theaqueous solution.

A filter may also be part of a system for capturing atmospheric carbondioxide as described above. For example, an ultrafiltration device orother filtration unit selected to separate the catalyst from the aqueoussolution before further processing the aqueous solution may be included.The filter mechanically separates the catalyst from the aqueous stream.

The aqueous stream, substantially free of catalyst, may then be provided(e.g., flows or is pumped) to a membrane separation unit (as describedabove). In the membrane separation unit, the aqueous stream is processedto separate the buffer species from the dissolved carbon dioxide. Thisselective separation yields two aqueous stream, with one stream having agreater concentration of buffer species the other stream, which has agreater concentration of dissolved carbon dioxide.

The membrane may be an ion exchange membrane. In an example, the ionexchange membrane is a monovalent anion exchange membrane. The membranemay be used in a process such as, for example, electrodialysis, reverseosmosis, ultrafiltration, microfiltration, nano-filtration, diffusiondialysis, Donnan dialysis, piezodialysis, pervaporation, or anotherappropriate process.

After the separation of the carbon dioxide from the buffer species, theaqueous stream is provided to an optional mixer and returned to thecontactor, or simply returned to the contactor directly. All or part ofthe aqueous stream may be optionally provided to a gas stripper andsubjected to an increased temperature, a decreased pressure, or both, ina temperature swing regeneration process, pressure swing regenerationprocess, or combination thereof, to further shift the chemicalequilibrium between the dissolved form of the carbon dioxide and thecarbon dioxide.

Such an atmospheric carbon dioxide capture system can be operated in acontinuous mode, in which multiple aqueous streams are combined andprovided to the contactor at the same time a carbon dioxide-enriched-gasstream flows from the contactor to the filter. Air or other gaseouscomponents may be vented through an outlet of the contactor to theatmosphere or collected as a gaseous stream. Accordingly, otherimplementations are within the scope of the following claims.

What is claimed is:
 1. A method for reducing a life cycle carbonemissions intensity of a fuel, comprising: injecting, into a firstwellbore, a carbon dioxide fluid produced from an industrial processthat supplies one or more products or services; producing a hydrocarbonfluid from a second wellbore to a terranean surface; producing a fuelfrom the produced hydrocarbon fluid; and determining that the producedfuel comprises a reduced life cycle carbon emissions intensity valuebased on a life cycle emissions credit for at least one of the producedhydrocarbon fluid or the produced fuel based on the injection of thecarbon dioxide fluid produced from the industrial process that suppliesone or more products or services.
 2. The method of claim 1, wherein thefirst and second wellbores are the same wellbore.
 3. The method of claim1, wherein the industrial process comprises a fossil fuel power plantand the one or more products or services comprise electricity.
 4. Themethod of claim 1, wherein the industrial process comprises at least oneof a natural gas processing facility, a steel production facility, acement production facility, an industrial oxyfuel combustion process, ahydrogen production process, or a fertilizer production process.
 5. Themethod of claim 1, further comprising: receiving at least a portion ofthe injected carbon dioxide fluid from the first wellbore at theterranean surface within the hydrocarbon fluid; separating the portionof the injected carbon dioxide fluid from the hydrocarbon fluid; andre-injecting the separated portion of the injected carbon dioxide fluidinto the first wellbore.
 6. The method of claim 1, further comprisingsequestering at least a portion of the injected carbon dioxide fluid ina subterranean zone.
 7. The method of claim 1, the produced fuelcomprises the reduced life cycle carbon emissions intensity value,relative to a baseline life cycle carbon emissions intensity value,based on the injection of the carbon dioxide fluid produced from theindustrial process.
 8. A method for reducing a life cycle carbonemissions intensity of a fuel, comprising: capturing a carbon dioxidefluid from an industrial process that supplies one or more products orservices; and providing the captured carbon dioxide fluid to a containerthat supplies the captured carbon dioxide fluid as an injectant to awellbore that produces a hydrocarbon fluid that is refined into a fuel,at least one of the hydrocarbon fluid or the fuel comprising a reducedlife cycle carbon emissions intensity value based on at least one of theinjectant of carbon dioxide fluid or the industrial process thatsupplies one or more products or services.
 9. The method of claim 8,wherein the industrial process comprises at least one of a carbonintensity reductions or an emissions credit for at least one of theproduced hydrocarbon fluid or a fuel produced from the producedhydrocarbon fluid in a refining process.
 10. The method of claim 9,wherein the fuel comprises a transportation fuel for consumer vehicles.11. The method of claim 8, wherein the industrial process comprises atleast one of an industrial separation process, a post-combustionseparation process, a pre-combustion separation process, or an oxyfuelseparation process.
 12. The method of claim 11, wherein the industrialseparation process comprises a raw material input and a fuel input andan output product that comprises carbon dioxide separable from theoutput product and compressible into the carbon dioxide fluid.
 13. Themethod of claim 12, wherein the raw material input and the fuel inputare a single input to the industrial separation process.
 14. The methodof claim 11, wherein the post-combustion separation process comprises anair input and a fuel input to a combustion process and an output fromthe combustion process that comprises heat, power, and a product thatcomprises carbon dioxide separable from the product and compressibleinto the carbon dioxide fluid.
 15. The method of claim 11, wherein thepre-combustion separation process comprises an air input and a fuelinput for a gasification process and an output from the gasificationprocess that comprises hydrogen and carbon dioxide separable from thehydrogen and compressible into the carbon dioxide fluid.
 16. The methodof claim 11, wherein the oxyfuel separation process comprises an oxygeninput and a fuel input to a combustion process and a flue gas outputfrom the combustion process that comprises at least water and carbondioxide separable from the water and compressible into the carbondioxide fluid.
 17. The method of claim 8, wherein the industrial processcomprises at least one of a fossil fuel power plant that generateselectricity, a natural gas processing facility, a steel productionfacility, a cement production facility, an industrial oxyfuel combustionprocess, a hydrogen production process, or a fertilizer productionprocess.
 18. A method for providing transportation fuel, comprising:receiving a fuel refined from a raw hydrocarbon fluid produced from ageologic formation into which a fluid that contains carbon dioxidecaptured from an industrial process that supplies one or more productsor services is injected; and providing the fuel as a transportationfuel, the transportation fuel comprising a reduced life cycle carbonemissions intensity value based on its association with at least one ofthe raw hydrocarbon fluid, the fluid that contains carbon dioxidecaptured from the industrial process, or the industrial process thatsupplies the one or more products or services.
 19. The method of claim18, further comprising completing a transaction to effect at least oneof: selling the transportation fuel to a transportation fuel provider;selling an emissions credit associated with a carbon intensity reductionto a transportation fuel provider or credit trading entity; orsubmitting an emissions credit associated with a carbon intensityreduction to a regulatory agency responsible for regulating fuel carbonintensity.
 20. The method of claim 18, wherein the industrial processcomprises a basis for at least one of a carbon intensity reductions oran emissions credit for at least one of the raw hydrocarbon fluid or thefuel refined from the raw hydrocarbon fluid.
 21. The method of claim 18,wherein the industrial process comprises at least one of an industrialseparation process, a post-combustion separation process, apre-combustion separation process, or an oxyfuel separation process. 22.The method of claim 18, wherein the industrial process comprises afossil fuel power plant and the one or more products or servicescomprise electricity.
 23. The method of claim 18, wherein the industrialprocess comprises at least one of a natural gas processing facility, asteel production facility, a cement production facility, an industrialoxyfuel combustion process, a hydrogen production process, or afertilizer production process.
 24. A method of producing a hydrocarbonfuel with reduced lifecycle carbon emissions intensity, the methodcomprising: receiving a hydrocarbon fluid that has been produced from ageologic formation through a wellbore to a terranean surface, thehydrocarbon fluid produced, at least partially, from the geologicformation with carbon dioxide fluid injected into the geologicformation, the carbon dioxide fluid supplied from an industrial processthat supplies one or more products or services; and refining thereceived hydrocarbon fluid into a fuel by a refining process, the fuelcomprising a reduced lifecycle emissions intensity value based onproduction of the fuel with at least one of the hydrocarbon fluid or thecarbon dioxide fluid associated with the industrial process thatsupplied one or more products or services.
 25. The method of claim 24,wherein the industrial process that supplies one or more products orservices comprises a basis for at least one of a carbon intensityreductions or an emissions credit for at least one of the producedhydrocarbon fluid or the fuel produced from the produced hydrocarbonfluid.
 26. The method of claim 24, wherein the fuel comprises alow-carbon consumer transportation fuel.
 27. The method of claim 24,wherein the industrial process comprises at least one of an industrialseparation process, a post-combustion separation process, apre-combustion separation process, or an oxyfuel separation process. 28.The method of claim 24, wherein the industrial process comprises afossil fuel power plant and the one or more products or servicescomprise electricity.
 29. A method for reducing a life cycle carbonemissions intensity of a hydrocarbon fluid, comprising: injecting, intoa first wellbore, a carbon dioxide fluid produced from an industrialprocess that supplies one or more products or services; producing ahydrocarbon fluid from a second wellbore to a terranean surface;determining that the produced hydrocarbon fluid comprises a reduced lifecycle carbon emissions intensity value based on a life cycle emissionscredit associated with the injection of the carbon dioxide fluidproduced from the industrial process that supplies one or more productsor services.
 30. The method of claim 29, wherein the first and secondwellbores are the same wellbore.
 31. The method of claim 29, wherein theindustrial process comprises a fossil fuel power plant and the one ormore products or services comprise electricity.
 32. The method of claim29, wherein the industrial process comprises at least one of a naturalgas processing facility, a steel production facility, a cementproduction facility, an industrial oxyfuel combustion process, ahydrogen production process, or a fertilizer production process.
 33. Themethod of claim 29, further comprising: receiving at least a portion ofthe injected carbon dioxide fluid from the first wellbore at theterranean surface within the hydrocarbon fluid; separating the portionof the injected carbon dioxide fluid from the hydrocarbon fluid; andre-injecting the separated portion of the injected carbon dioxide fluidinto the first wellbore.
 34. The method of claim 29, further comprisingsequestering at least a portion of the injected carbon dioxide fluid ina subterranean zone.
 35. The method of claim 29, the producedhydrocarbon fluid comprises the reduced life cycle carbon emissionsintensity value, relative to a baseline life cycle carbon emissionsintensity value, based on the injection of the carbon dioxide fluidproduced from the industrial process.
 36. A method for providinghydrocarbon fluid, comprising: receiving a hydrocarbon fluid producedfrom a geologic formation into which a fluid that contains carbondioxide captured from an industrial process that supplies one or moreproducts or services is injected; determining that the hydrocarbon fluidcomprises a reduced life cycle carbon emissions intensity value based onits association with at least one of the carbon dioxide captured fromthe industrial process or the industrial process that supplies the oneor more products or services; and providing the hydrocarbon fluid as aproduct.
 37. The method of claim 36, further comprising completing atransaction to effect at least one of: selling the hydrocarbon fluid toa hydrocarbon fluid refiner; selling an emissions credit associated witha carbon intensity reduction to a transportation fuel provider or credittrading entity; or submitting an emissions credit associated with acarbon intensity reduction to a regulatory agency that regulates fuelcarbon intensity.
 38. The method of claim 36, wherein the industrialprocess comprises a basis for at least one of a carbon intensityreductions or an emissions credit for at least one of the rawhydrocarbon fluid or the fuel refined from the raw hydrocarbon fluid.39. The method of claim 36, wherein the industrial process comprises atleast one of an industrial separation process, a post-combustionseparation process, a pre-combustion separation process, or an oxyfuelseparation process.
 40. The method of claim 36, wherein the industrialprocess comprises a fossil fuel power plant and the one or more productsor services comprise electricity.
 41. The method of claim 36, whereinthe industrial process comprises at least one of a natural gasprocessing facility, a steel production facility, a cement productionfacility, an industrial oxyfuel combustion process, a hydrogenproduction process, or a fertilizer production process.